Document_and_Entity_Informatio
Document and Entity Information | 9 Months Ended |
Sep. 30, 2013 | |
Entity Registrant Name | 'EXELON CORP |
Entity Central Index Key | '0001109357 |
Document Type | '10-Q |
Document Period End Date | 30-Sep-13 |
Amendment Flag | 'false |
Document Fiscal Year Focus | '2013 |
Document Fiscal Period Focus | 'Q3 |
Current Fiscal Year End Date | '--12-31 |
Entity 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 | 856,903,972 |
Exelon Generation Co L L C [Member] | ' |
Entity Registrant Name | 'EXELON GENERATION CO LLC |
Entity Central Index Key | '0001168165 |
Entity Filer Category | 'Non-accelerated Filer |
Commonwealth Edison Co [Member] | ' |
Entity Registrant Name | 'COMMONWEALTH EDISON CO |
Entity Central Index Key | '0000022606 |
Entity Filer Category | 'Non-accelerated Filer |
Entity Common Stock Shares Outstanding | 127,016,855 |
PECO Energy Co [Member] | ' |
Entity Registrant Name | 'PECO ENERGY CO |
Entity Central Index Key | '0000078100 |
Entity Filer Category | 'Non-accelerated Filer |
Entity Common Stock Shares Outstanding | 170,478,507 |
Baltimore Gas and Electric Company [Member] | ' |
Entity Registrant Name | 'BALTIMORE GAS AND ELECTRIC |
Entity Central Index Key | '0000009466 |
Entity 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 $) | 3 Months Ended | 9 Months Ended | ||||||
In Millions, except Per Share data, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | ||||
Operating revenues [Abstract] | ' | ' | ' | ' | ||||
Total operating revenues | $6,502 | [1] | $6,579 | [1] | $18,725 | [2] | $17,235 | [2] |
Operating expenses | ' | ' | ' | ' | ||||
Purchased power | 2,743 | 3,026 | 8,143 | 7,398 | ||||
Operating and maintenance | 1,735 | 2,170 | 5,391 | 5,979 | ||||
Depreciation and amortization | 530 | 500 | 1,606 | 1,376 | ||||
Taxes other than income | 277 | 290 | 825 | 737 | ||||
Total operating expenses | 5,285 | 5,986 | 15,965 | 15,490 | ||||
Gain (loss) on equity method investments | 37 | 10 | 7 | -69 | ||||
Operating income | 1,254 | 603 | 2,767 | 1,676 | ||||
Other income and deductions | ' | ' | ' | ' | ||||
Interest expense | -228 | -240 | -1,091 | -678 | ||||
Interest expense to affiliates, net | -6 | -6 | -19 | -19 | ||||
Other, net | 155 | 101 | 311 | 253 | ||||
Total other income and deductions | -79 | -145 | -799 | -444 | ||||
Income before income taxes | 1,175 | 458 | 1,968 | 1,232 | ||||
Income taxes | 439 | 161 | 733 | 445 | ||||
Net income | 736 | 297 | 1,235 | 787 | ||||
Net income (loss) attributable to noncontrolling interests and preferred security dividends | 2 | -1 | -11 | -5 | ||||
Net income on common stock | 738 | 296 | 1,224 | 782 | ||||
Pension and non-pension postretirement benefit plans: | ' | ' | ' | ' | ||||
Prior service benefit reclassified to periodic benefit cost | -1 | ' | 0 | -1 | ||||
Actuarial loss reclassified to periodic cost | -49 | -44 | -151 | -126 | ||||
Transition obligation reclassified to periodic cost | ' | ' | ' | -2 | ||||
Pension and non-pension postretirement benefit plans valuation adjustment | -8 | -67 | 69 | -78 | ||||
Deferred Compensation Unit Valuation Adjustment | 0 | ' | 10 | ' | ||||
Change in unrealized gain (loss) on cash-flow hedges | -46 | -88 | -169 | -29 | ||||
Change in unrealized income (loss) on equity investments | 16 | 17 | 51 | 23 | ||||
Change in unrealized income (loss) on foreign currency translation | 0 | 2 | -5 | 0 | ||||
Change in unrealized gain (loss) on marketable securities | 0 | 0 | -1 | 0 | ||||
Other comprehensive income (loss) | 12 | -92 | 106 | [3] | 45 | |||
Comprehensive income | 748 | 205 | 1,341 | 832 | ||||
Average shares of common stock outstanding: | ' | ' | ' | ' | ||||
Basic | 857 | 854 | 856 | 804 | ||||
Diluted | 860 | 857 | 860 | 806 | ||||
Earnings per average common share - basic | ' | ' | ' | ' | ||||
Net income | $0.86 | $0.35 | $1.43 | $0.97 | ||||
Earnings per average common share - diluted | ' | ' | ' | ' | ||||
Net income | $0.86 | $0.35 | $1.42 | $0.97 | ||||
Dividends per common share | $0.31 | $0.53 | $1.15 | $1.58 | ||||
Exelon Generation Co L L C [Member] | ' | ' | ' | ' | ||||
Operating revenues [Abstract] | ' | ' | ' | ' | ||||
Operating revenues | 3,871 | 3,558 | 10,729 | 9,276 | ||||
Operating revenues from affiliates | 384 | 473 | 1,129 | 1,263 | ||||
Total operating revenues | 4,255 | 4,031 | 11,858 | 10,539 | ||||
Operating expenses | ' | ' | ' | ' | ||||
Purchased power and fuel | 2,179 | 2,122 | 6,294 | 5,018 | ||||
Operating and maintenance | 936 | 1,289 | 2,943 | 3,319 | ||||
Operating and maintenance from affiliate | 140 | 140 | 434 | 467 | ||||
Depreciation and amortization | 218 | 207 | 643 | 564 | ||||
Taxes other than income | 98 | 109 | 292 | 272 | ||||
Total operating expenses | 3,571 | 3,867 | 10,606 | 9,640 | ||||
Gain (loss) on equity method investments | 37 | 10 | 7 | -69 | ||||
Operating income | 721 | 174 | 1,259 | 830 | ||||
Other income and deductions | ' | ' | ' | ' | ||||
Interest expense | -82 | -85 | -257 | -223 | ||||
Other, net | 134 | 83 | 229 | 185 | ||||
Total other income and deductions | 52 | -2 | -28 | -38 | ||||
Income before income taxes | 773 | 172 | 1,231 | 792 | ||||
Income taxes | 288 | 85 | 436 | 373 | ||||
Net income | 485 | 87 | 795 | 419 | ||||
Income (Loss) attributable to noncontrolling interest | 5 | 4 | 6 | 6 | ||||
Net income on membership interest | 490 | 91 | 801 | 425 | ||||
Pension and non-pension postretirement benefit plans: | ' | ' | ' | ' | ||||
Change in unrealized gain (loss) on cash-flow hedges | -49 | -171 | -316 | -185 | ||||
Change in unrealized income (loss) on equity investments | 16 | 17 | 52 | 23 | ||||
Change in unrealized income (loss) on foreign currency translation | 1 | 2 | -5 | 0 | ||||
Change in unrealized gain (loss) on marketable securities | ' | 0 | -1 | -1 | ||||
Other comprehensive income (loss) | -32 | -152 | -270 | [3] | -163 | |||
Comprehensive income | 453 | -65 | 525 | 256 | ||||
Commonwealth Edison Co [Member] | ' | ' | ' | ' | ||||
Operating revenues [Abstract] | ' | ' | ' | ' | ||||
Operating revenues | 1,155 | 1,484 | 3,393 | 4,152 | ||||
Operating revenues from affiliates | 1 | 0 | 2 | 2 | ||||
Total operating revenues | 1,156 | 1,484 | 3,395 | 4,154 | ||||
Operating expenses | ' | ' | ' | ' | ||||
Purchased power | 158 | 498 | 522 | 1,255 | ||||
Purchased power from affiliate | 143 | 180 | 409 | 631 | ||||
Operating and maintenance | 296 | 313 | 907 | 882 | ||||
Operating and maintenance from affiliate | 37 | 37 | 113 | 118 | ||||
Depreciation and amortization | 164 | 157 | 501 | 458 | ||||
Taxes other than income | 80 | 81 | 225 | 224 | ||||
Total operating expenses | 878 | 1,266 | 2,677 | 3,568 | ||||
Operating income | 278 | 218 | 718 | 586 | ||||
Other income and deductions | ' | ' | ' | ' | ||||
Interest expense | -71 | -71 | -493 | -221 | ||||
Interest expense to affiliates, net | -3 | -3 | -10 | -9 | ||||
Other, net | 7 | 5 | 18 | 12 | ||||
Total other income and deductions | -67 | -69 | -485 | -218 | ||||
Income before income taxes | 211 | 149 | 233 | 368 | ||||
Income taxes | 85 | 59 | 93 | 149 | ||||
Net income | 126 | 90 | 140 | 219 | ||||
Pension and non-pension postretirement benefit plans: | ' | ' | ' | ' | ||||
Change in unrealized gain (loss) on marketable securities | ' | ' | ' | 1 | ||||
Other comprehensive income (loss) | ' | ' | ' | 1 | ||||
Comprehensive income | 126 | 90 | 140 | 220 | ||||
PECO Energy Co [Member] | ' | ' | ' | ' | ||||
Operating revenues [Abstract] | ' | ' | ' | ' | ||||
Operating revenues | 727 | 805 | 2,294 | 2,393 | ||||
Operating revenues from affiliates | 1 | 1 | 1 | 3 | ||||
Total operating revenues | 728 | 806 | 2,295 | 2,396 | ||||
Operating expenses | ' | ' | ' | ' | ||||
Purchased power | 207 | 155 | 632 | 626 | ||||
Purchased power from affiliate | 82 | 171 | 321 | 407 | ||||
Operating and maintenance | 162 | 172 | 480 | 491 | ||||
Operating and maintenance from affiliate | 24 | 27 | 74 | 83 | ||||
Depreciation and amortization | 57 | 55 | 171 | 161 | ||||
Taxes other than income | 41 | 48 | 121 | 122 | ||||
Total operating expenses | 573 | 628 | 1,799 | 1,890 | ||||
Operating income | 155 | 178 | 496 | 506 | ||||
Other income and deductions | ' | ' | ' | ' | ||||
Interest expense | -26 | -29 | -77 | -85 | ||||
Interest expense to affiliates, net | -3 | -3 | -9 | -9 | ||||
Other, net | 1 | 2 | 4 | 6 | ||||
Total other income and deductions | -28 | -30 | -82 | -88 | ||||
Income before income taxes | 127 | 148 | 414 | 418 | ||||
Income taxes | 35 | 25 | 122 | 118 | ||||
Net income | 92 | 123 | 292 | 300 | ||||
Preferred security dividends | 0 | -1 | -7 | -3 | ||||
Net income on common stock | 92 | 122 | 285 | 297 | ||||
Pension and non-pension postretirement benefit plans: | ' | ' | ' | ' | ||||
Change in unrealized gain (loss) on marketable securities | ' | ' | ' | 1 | ||||
Other comprehensive income (loss) | ' | ' | ' | 1 | ||||
Comprehensive income | 92 | 123 | 292 | 301 | ||||
Baltimore Gas and Electric Company [Member] | ' | ' | ' | ' | ||||
Operating revenues [Abstract] | ' | ' | ' | ' | ||||
Operating revenues | 735 | 716 | 2,261 | 2,023 | ||||
Operating revenues from affiliates | 2 | 4 | 10 | 9 | ||||
Total operating revenues | 737 | 720 | 2,271 | 2,032 | ||||
Operating expenses | ' | ' | ' | ' | ||||
Purchased power and fuel | 202 | 253 | 703 | 747 | ||||
Purchased power and fuel from affiliate | 144 | 120 | 356 | 296 | ||||
Operating and maintenance | 125 | 172 | 391 | 460 | ||||
Operating and maintenance from affiliate | 21 | 29 | 59 | 97 | ||||
Depreciation and amortization | 78 | 68 | 252 | 218 | ||||
Taxes other than income | 53 | 48 | 162 | 143 | ||||
Total operating expenses | 623 | 690 | 1,923 | 1,961 | ||||
Operating income | 114 | 30 | 348 | 71 | ||||
Other income and deductions | ' | ' | ' | ' | ||||
Interest expense | -29 | -35 | -94 | -110 | ||||
Other, net | 4 | 5 | 13 | 18 | ||||
Total other income and deductions | -25 | -30 | -81 | -92 | ||||
Income before income taxes | 89 | 0 | 267 | -21 | ||||
Income taxes | 36 | 0 | 107 | -7 | ||||
Net income | 53 | 0 | 160 | -14 | ||||
Preferred security dividends | -3 | -4 | -10 | -10 | ||||
Net income on common stock | 50 | -4 | 150 | -24 | ||||
Pension and non-pension postretirement benefit plans: | ' | ' | ' | ' | ||||
Comprehensive income | $53 | $0 | $160 | ($14) | ||||
[1] | For the three months ended September 30, 2013 and 2012, utility taxes of $21 million and $28 million, respectively, are included in revenues and expenses for Generation. For the three months ended September 30, 2013 and 2012, utility taxes of $65 million and $67 million, respectively, are included in revenues and expenses for ComEd. For the three months ended September 30, 2013 and 2012, utility taxes of $33 million and $40 million, respectively, are included in revenues and expenses for PECO. For the three months ended September 30, 2013 and 2012, utility taxes of $20 million and $20 million, respectively, are included in revenues and expenses for BGE. | |||||||
[2] | For the nine months ended September 30, 2013 and 2012, utility taxes of $60 million and $60 million, respectively, are included in revenues and expenses for Generation. For the nine months ended September 30, 2013 and 2012, utility taxes of $182 million and $182 million, respectively, are included in revenues and expenses for ComEd. For the nine months ended September 30, 2013 and 2012, utility taxes of $97 million and $108 million, respectively, are included in revenues and expenses for PECO. For the nine months ended September 30, 2013 and period of March 12, 2012 through September 30, 2012, utility taxes of $62 million and $42 million, respectively, are included in revenues and expenses for BGE. | |||||||
[3] | (a) 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 (Unaudited) (Parenthetical) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Prior service costs | ' | $1 | ' | $2 |
Actuarial loss reclassified to periodic cost, taxes | -33 | -28 | -97 | -82 |
Transition obligation | ' | 1 | ' | 2 |
Pension and non-pension postretirement benefit plan valuation adjustment, taxes | 6 | 43 | -44 | 51 |
Change in unrealized gain (loss) on cash flow hedges, taxes | -35 | -57 | -109 | 36 |
Change in unrealized gain (loss) on marketable securities, taxes | ' | ' | ' | 1 |
Change in unrealized gain (loss) on equity investments taxes | 9 | 11 | 32 | 15 |
Deferred Compensation Unit Valuation Adjustment tax | ' | ' | 6 | ' |
Exelon Generation Co L L C [Member] | ' | ' | ' | ' |
Change in unrealized gain (loss) on cash flow hedges, taxes | -36 | -113 | -209 | -122 |
Change in unrealized gain (loss) on equity investments taxes | $9 | $11 | $32 | $15 |
Consolidated_Statements_of_Cas
Consolidated Statements of Cash Flows (Unaudited) (USD $) | 9 Months Ended | |
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 |
Cash flows from operating activities | ' | ' |
Net income | $1,235 | $787 |
Adjustments to reconcile net income to net cash flows provided by operating activities: | ' | ' |
Depreciation, amortization and accretion | 2,844 | 2,909 |
Impairment of assets held for sale | 0 | 278 |
Deferred income taxes and amortization of investment tax credits | -164 | 263 |
Net fair value changes related to derivatives | -229 | -377 |
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments | -95 | -142 |
Other non-cash operating activities | 738 | 1,235 |
Changes in assets and liabilities: | ' | ' |
Accounts receivable | 54 | 228 |
Inventories | -103 | 12 |
Accounts payable, accrued expenses and other current liabilities | -243 | -817 |
Option premiums paid, net | -38 | -122 |
Counterparty collateral (posted) received, net | -73 | 408 |
Income taxes | 863 | 465 |
Pension and non-pension postretirement benefit contributions | -360 | -131 |
Other assets and liabilities | -35 | -422 |
Net cash flows provided by operating activities | 4,394 | 4,574 |
Cash flows from investing activities | ' | ' |
Capital expenditures | -3,887 | -4,162 |
Proceeds from nuclear decommissioning trust fund sales | 3,344 | 6,262 |
Investment in nuclear decommissioning trust funds | -3,518 | -6,422 |
Proceeds from sale of long-lived assets | 32 | ' |
Cash acquired from Constellation | 0 | 964 |
Acquisitions | ' | 0 |
Proceeds from sales of investments | 20 | 26 |
Purchases of investments | -3 | -13 |
Change in restricted cash | -23 | -38 |
Other investing activities | 65 | 41 |
Net cash flows provided by (used in) investing activities | -3,970 | -3,342 |
Cash flows from financing activities | ' | ' |
Payment of accounts receivable agreement | -210 | ' |
Changes in short-term debt | 205 | -139 |
Issuance of long-term debt | 2,031 | 1,558 |
Retirement or repayment of long-term debt | -1,156 | -731 |
Redemption of preferred securities | -93 | ' |
Dividends paid on common stock | -981 | -1,226 |
Dividends paid to former Constellation shareholders | 0 | -51 |
Proceeds from employee stock plans | 40 | 61 |
Other financing activities | -102 | -20 |
Net cash flows used in financing activities | -266 | -548 |
Increase (decrease) in cash and cash equivalents | 158 | 684 |
Cash and cash equivalents at beginning of period | 1,486 | 1,016 |
Cash and cash equivalents at end of period | 1,644 | 1,700 |
Exelon Generation Co L L C [Member] | ' | ' |
Cash flows from operating activities | ' | ' |
Net income | 795 | 419 |
Adjustments to reconcile net income to net cash flows provided by operating activities: | ' | ' |
Depreciation, amortization and accretion | 1,937 | 2,178 |
Impairment of assets held for sale | 0 | 278 |
Deferred income taxes and amortization of investment tax credits | 183 | 69 |
Net fair value changes related to derivatives | -222 | -345 |
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments | -95 | -142 |
Other non-cash operating activities | 375 | 422 |
Changes in assets and liabilities: | ' | ' |
Accounts receivable | 57 | 189 |
Receivables from and payables to affiliates, net | -2 | -58 |
Inventories | -81 | 34 |
Accounts payable, accrued expenses and other current liabilities | -162 | -546 |
Option premiums paid, net | -38 | -122 |
Counterparty collateral (posted) received, net | -123 | 315 |
Income taxes | 315 | 565 |
Pension and non-pension postretirement benefit contributions | -123 | -48 |
Other assets and liabilities | -163 | -195 |
Net cash flows provided by operating activities | 2,657 | 3,013 |
Cash flows from investing activities | ' | ' |
Capital expenditures | -1,995 | -2,602 |
Proceeds from nuclear decommissioning trust fund sales | 3,344 | 6,262 |
Investment in nuclear decommissioning trust funds | -3,518 | -6,422 |
Proceeds from sale of long-lived assets | 32 | ' |
Cash acquired from Constellation | 0 | 708 |
Acquisitions | ' | 0 |
Change in restricted cash | -30 | 0 |
Other investing activities | 18 | -2 |
Net cash flows provided by (used in) investing activities | -2,149 | -2,056 |
Cash flows from financing activities | ' | ' |
Changes in short-term debt | 12 | -41 |
Change in Exelon intercompany money pool borrowings | 0 | ' |
Issuance of long-term debt | 831 | 957 |
Retirement or repayment of long-term debt | -471 | -138 |
Distribution to member | -550 | -1,384 |
Contributions from member | 0 | 0 |
Other financing activities | -73 | -17 |
Net cash flows used in financing activities | -251 | -623 |
Increase (decrease) in cash and cash equivalents | 257 | 334 |
Cash and cash equivalents at beginning of period | 671 | 496 |
Cash and cash equivalents at end of period | 928 | 830 |
Commonwealth Edison Co [Member] | ' | ' |
Cash flows from operating activities | ' | ' |
Net income | 140 | 219 |
Adjustments to reconcile net income to net cash flows provided by operating activities: | ' | ' |
Depreciation, amortization and accretion | 501 | 458 |
Deferred income taxes and amortization of investment tax credits | -152 | 198 |
Other non-cash operating activities | 26 | 310 |
Changes in assets and liabilities: | ' | ' |
Accounts receivable | -21 | 22 |
Receivables from and payables to affiliates, net | -32 | -32 |
Inventories | -12 | -11 |
Accounts payable, accrued expenses and other current liabilities | 48 | -49 |
Counterparty collateral (posted) received, net | 50 | 93 |
Income taxes | 262 | 116 |
Pension and non-pension postretirement benefit contributions | -120 | -19 |
Other assets and liabilities | 160 | -124 |
Net cash flows provided by operating activities | 850 | 1,181 |
Cash flows from investing activities | ' | ' |
Capital expenditures | -1,074 | -896 |
Proceeds from sales of investments | 5 | 26 |
Purchases of investments | -3 | -13 |
Change in restricted cash | -3 | 0 |
Other investing activities | 33 | 12 |
Net cash flows provided by (used in) investing activities | -1,042 | -871 |
Cash flows from financing activities | ' | ' |
Changes in short-term debt | 153 | 35 |
Issuance of long-term debt | 350 | 0 |
Retirement or repayment of long-term debt | -252 | -450 |
Contributions from parent | 0 | 0 |
Dividends paid on common stock | -165 | -95 |
Other financing activities | -4 | -3 |
Net cash flows used in financing activities | 82 | -513 |
Increase (decrease) in cash and cash equivalents | -110 | -203 |
Cash and cash equivalents at beginning of period | 144 | 234 |
Cash and cash equivalents at end of period | 34 | 31 |
PECO Energy Co [Member] | ' | ' |
Cash flows from operating activities | ' | ' |
Net income | 292 | 300 |
Adjustments to reconcile net income to net cash flows provided by operating activities: | ' | ' |
Depreciation, amortization and accretion | 171 | 161 |
Deferred income taxes and amortization of investment tax credits | 35 | 27 |
Other non-cash operating activities | 84 | 96 |
Changes in assets and liabilities: | ' | ' |
Accounts receivable | 41 | 36 |
Receivables from and payables to affiliates, net | -25 | 15 |
Inventories | 4 | 10 |
Accounts payable, accrued expenses and other current liabilities | 9 | -75 |
Income taxes | 66 | 127 |
Pension and non-pension postretirement benefit contributions | -10 | -12 |
Other assets and liabilities | -47 | -57 |
Net cash flows provided by operating activities | 620 | 628 |
Cash flows from investing activities | ' | ' |
Capital expenditures | -374 | -274 |
Changes in intercompany money pool | -1 | 5 |
Change in restricted cash | -1 | 2 |
Other investing activities | 8 | 8 |
Net cash flows provided by (used in) investing activities | -368 | -259 |
Cash flows from financing activities | ' | ' |
Changes in short-term debt | -210 | 0 |
Issuance of long-term debt | 550 | 350 |
Redemption of preferred securities | -93 | ' |
Dividends paid on common stock | -248 | -258 |
Dividends paid on preferred securities | -1 | -3 |
Other financing activities | -3 | -4 |
Net cash flows used in financing activities | -5 | 85 |
Increase (decrease) in cash and cash equivalents | 247 | 454 |
Cash and cash equivalents at beginning of period | 362 | 194 |
Cash and cash equivalents at end of period | 609 | 648 |
Baltimore Gas and Electric Company [Member] | ' | ' |
Cash flows from operating activities | ' | ' |
Net income | 160 | -14 |
Adjustments to reconcile net income to net cash flows provided by operating activities: | ' | ' |
Depreciation, amortization and accretion | 252 | 218 |
Deferred income taxes and amortization of investment tax credits | 105 | 101 |
Other non-cash operating activities | 105 | 148 |
Changes in assets and liabilities: | ' | ' |
Accounts receivable | -28 | 0 |
Receivables from and payables to affiliates, net | -12 | 2 |
Inventories | -15 | 21 |
Accounts payable, accrued expenses and other current liabilities | -5 | 4 |
Income taxes | 6 | -50 |
Pension and non-pension postretirement benefit contributions | -16 | -13 |
Other assets and liabilities | -119 | -77 |
Net cash flows provided by operating activities | 433 | 340 |
Cash flows from investing activities | ' | ' |
Capital expenditures | -391 | -419 |
Change in restricted cash | -20 | -19 |
Other investing activities | 2 | 8 |
Net cash flows provided by (used in) investing activities | -409 | -430 |
Cash flows from financing activities | ' | ' |
Changes in short-term debt | 40 | 0 |
Issuance of long-term debt | 300 | 250 |
Retirement or repayment of long-term debt | -433 | -141 |
Contributions from parent | 0 | 66 |
Dividends paid on common stock | 0 | 0 |
Dividends paid on preferred securities | -10 | -10 |
Change in restricted cash for dividends | 0 | ' |
Other financing activities | -3 | -3 |
Net cash flows used in financing activities | -106 | 162 |
Increase (decrease) in cash and cash equivalents | -82 | 72 |
Cash and cash equivalents at beginning of period | 89 | 49 |
Cash and cash equivalents at end of period | $7 | $121 |
Consolidated_Balance_Sheets_Un
Consolidated Balance Sheets (Unaudited) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 | ||
In Millions, unless otherwise specified | ||||
Current assets | ' | ' | ||
Cash and cash equivalents | $1,600 | $1,411 | ||
Cash and cash equivalents of variable interest entities | 44 | 75 | ||
Restricted cash and investments | 60 | 86 | ||
Restricted cash and investments of variable interest entity | 87 | 47 | ||
Accounts receivable, net | ' | ' | ||
Customer | 2,584 | 2,795 | ||
Other | 1,232 | 1,141 | ||
Accounts receivable of variable interest entities | 177 | 292 | ||
Mark-to-market derivative assets | 730 | 938 | ||
Unamortized energy contracts assets | 460 | 886 | ||
Inventories, net | ' | ' | ||
Fossil fuel | 288 | 246 | ||
Materials and supplies | 821 | 768 | ||
Deferred income taxes | 292 | 131 | ||
Regulatory assets | 877 | 764 | ||
Other | 699 | 560 | ||
Total current assets | 9,951 | 10,140 | ||
Property, plant and equipment, net | 46,495 | 45,186 | ||
Deferred debits and other assets | ' | ' | ||
Regulatory assets | 6,509 | 6,497 | ||
Nuclear decommissioning trust funds | 7,776 | 7,248 | ||
Investments | 1,154 | 1,184 | ||
Investments in affiliates | 23 | 22 | ||
Investment in CENG | 1,939 | 1,849 | ||
Goodwill | 2,625 | 2,625 | ||
Mark-to-market derivative assets | 779 | 937 | ||
Pledged assets for Zion Station decommissioning | 486 | 614 | ||
Unamortized energy contracts assets | 803 | 1,073 | ||
Other | 1,121 | 1,186 | ||
Deferred income taxes | ' | 116 | ||
Total deferred debits and other assets | 23,215 | 23,235 | ||
Total assets | 79,661 | 78,561 | ||
Current liabilities | ' | ' | ||
Short-term borrowings | 214 | 0 | ||
Short-term notes payable - accounts receivable agreement | 0 | 210 | ||
Long-term debt due within one year | 1,461 | 975 | ||
Long-term debt of variable interest entities due within one year | 182 | 72 | ||
Accounts payable | 2,369 | 2,446 | ||
Accounts payable of variable interest entities | 108 | 202 | ||
Accrued expenses | 1,540 | 1,800 | ||
Deferred income taxes | 50 | 58 | ||
Regulatory liabilities | 314 | 368 | ||
Mark-to-market derivative liabilities | 126 | 352 | ||
Unamortized energy contract liabilities | 305 | 455 | ||
Other | 838 | 853 | ||
Total current liabilities | 7,507 | 7,791 | ||
Long-term debt | 17,583 | 17,190 | ||
Long-term debt of variable financing trusts | 648 | 648 | ||
Long-term debt of variable interest entity | 339 | 508 | ||
Deferred credits and other liabilities | ' | ' | ||
Deferred income taxes and unamortized investment tax credits | 11,931 | 11,551 | ||
Asset retirement obligations | 5,118 | 5,074 | ||
Pension obligations | 3,094 | 3,428 | ||
Non-pension postretirement benefit obligations | 2,764 | 2,662 | ||
Spent nuclear fuel obligation | 1,021 | 1,020 | ||
Regulatory liabilities | 4,204 | 3,981 | ||
Mark-to-market derivative liabilities | 218 | 281 | ||
Unamortized energy contract liabilities | 314 | 528 | ||
Payable for Zion Station decommissioning | 339 | 432 | ||
Other | 2,514 | 1,650 | ||
Total deferred credits and other liabilities | 31,517 | 30,607 | ||
Total liabilities | 57,594 | 56,744 | ||
Commitments and contingencies | ' | ' | ||
Preferred securities | 0 | 87 | ||
Shareholders' equity | ' | ' | ||
Common stock | 16,716 | 16,632 | ||
Treasury stock, at cost (35 and 35 shares held at December 31, 2010 and December 31, 2009, respectively) | -2,327 | -2,327 | ||
Retained earnings | 10,131 | 9,893 | ||
Accumulated other comprehensive income (loss), net | -2,661 | [1] | -2,767 | [1] |
Total shareholders' equity | 21,859 | 21,431 | ||
BGE preference stock not subject to mandatory redemption | 193 | 193 | ||
Noncontrolling interest | 15 | 106 | ||
Total equity | 22,067 | 21,730 | ||
Total liabilities and shareholders' equity | 79,661 | 78,561 | ||
Member's equity | ' | ' | ||
Accumulated other comprehensive income (loss), net | -2,661 | [1] | -2,767 | [1] |
Removal Costs [Member] | ' | ' | ||
Current liabilities | ' | ' | ||
Regulatory liabilities | 103 | 97 | ||
Deferred credits and other liabilities | ' | ' | ||
Regulatory liabilities | 1,420 | 1,406 | ||
Exelon Generation Co L L C [Member] | ' | ' | ||
Current assets | ' | ' | ||
Cash and cash equivalents | 884 | 596 | ||
Cash and cash equivalents of variable interest entities | 44 | 75 | ||
Restricted cash and cash equivalents | 0 | 0 | ||
Restricted cash and investments of variable interest entity | 37 | 16 | ||
Accounts receivable, net | ' | ' | ||
Customer | 1,489 | 1,482 | ||
Other | 417 | 472 | ||
Accounts receivable of variable interest entities | 175 | 292 | ||
Mark-to-market derivative assets | 730 | 938 | ||
Mark-to-market derivative assets with affiliates | 0 | 226 | ||
Receivables from affiliates | 107 | 141 | ||
Unamortized energy contracts assets | 460 | 886 | ||
Inventories, net | ' | ' | ||
Fossil fuel | 169 | 130 | ||
Materials and supplies | 661 | 626 | ||
Deferred income taxes | 177 | ' | ||
Other | 455 | 331 | ||
Total current assets | 5,805 | 6,211 | ||
Property, plant and equipment, net | 19,797 | 19,531 | ||
Deferred debits and other assets | ' | ' | ||
Nuclear decommissioning trust funds | 7,776 | 7,248 | ||
Investments | 401 | 420 | ||
Investments in affiliates | 0 | 0 | ||
Investment in CENG | 1,939 | 1,849 | ||
Mark-to-market derivative assets | 766 | 924 | ||
Prepaid pension asset | 1,927 | 1,975 | ||
Pledged assets for Zion Station decommissioning | 486 | 614 | ||
Unamortized energy contracts assets | 803 | 1,073 | ||
Other | 798 | 836 | ||
Total deferred debits and other assets | 14,896 | 14,939 | ||
Total assets | 40,498 | 40,681 | ||
Current liabilities | ' | ' | ||
Short-term borrowings | 21 | 0 | ||
Long-term debt due within one year | 544 | 24 | ||
Long-term debt of variable interest entities due within one year | 104 | 4 | ||
Accounts payable | 1,254 | 1,346 | ||
Accounts payable of variable interest entities | 108 | 202 | ||
Accrued expenses | 925 | 1,116 | ||
Payables to affiliates | 162 | 193 | ||
Borrowings from Exelon intercompany money pool | 0 | ' | ||
Deferred income taxes | 44 | 128 | ||
Mark-to-market derivative liabilities | 110 | 334 | ||
Unamortized energy contract liabilities | 276 | 378 | ||
Other | 348 | 372 | ||
Total current liabilities | 3,896 | 4,097 | ||
Long-term debt | 5,545 | 5,245 | ||
Long-term debt to affiliate | 1,528 | 2,007 | ||
Long-term debt of variable interest entity | 88 | 203 | ||
Deferred credits and other liabilities | ' | ' | ||
Deferred income taxes and unamortized investment tax credits | 5,899 | 5,398 | ||
Asset retirement obligations | 4,983 | 4,938 | ||
Non-pension postretirement benefit obligations | 843 | 755 | ||
Spent nuclear fuel obligation | 1,021 | 1,020 | ||
Payables to affiliates | 2,593 | 2,397 | ||
Mark-to-market derivative liabilities | 112 | 232 | ||
Unamortized energy contract liabilities | 311 | 516 | ||
Payable for Zion Station decommissioning | 339 | 432 | ||
Other | 789 | 776 | ||
Total deferred credits and other liabilities | 16,890 | 16,464 | ||
Total liabilities | 27,947 | 28,016 | ||
Commitments and contingencies | 0 | 0 | ||
Shareholders' equity | ' | ' | ||
Accumulated other comprehensive income (loss), net | 243 | [1] | 513 | [1] |
Noncontrolling interest | 17 | 108 | ||
Member's equity | ' | ' | ||
Membership interest | 8,872 | 8,876 | ||
Undistributed earnings | 3,419 | 3,168 | ||
Accumulated other comprehensive income (loss), net | 243 | [1] | 513 | [1] |
Total member's equity | 12,534 | 12,557 | ||
Total equity | 12,551 | 12,665 | ||
Total liabilities and equity | 40,498 | 40,681 | ||
Commonwealth Edison Co [Member] | ' | ' | ||
Current assets | ' | ' | ||
Cash and cash equivalents | 34 | 144 | ||
Restricted cash and cash equivalents | 3 | 0 | ||
Accounts receivable, net | ' | ' | ||
Customer | 443 | 539 | ||
Other | 525 | 452 | ||
Inventories, net | ' | ' | ||
Inventories, net | 103 | 91 | ||
Deferred income taxes | 18 | 83 | ||
Receivable from Exelon intercompany money pool | 172 | ' | ||
Counterparty collateral deposited | 3 | 53 | ||
Regulatory assets | 335 | 388 | ||
Other | 31 | 25 | ||
Total current assets | 1,495 | 1,775 | ||
Property, plant and equipment, net | 14,444 | 13,826 | ||
Deferred debits and other assets | ' | ' | ||
Regulatory assets | 819 | 666 | ||
Investments | 5 | 8 | ||
Investments in affiliates | 6 | 6 | ||
Goodwill | 2,625 | 2,625 | ||
Receivable from affiliate | 2,361 | 2,039 | ||
Prepaid pension asset | 1,631 | 1,661 | ||
Other | 300 | 299 | ||
Total deferred debits and other assets | 7,747 | 7,304 | ||
Total assets | 23,686 | 22,905 | ||
Current liabilities | ' | ' | ||
Short-term borrowings | 153 | 0 | ||
Long-term debt due within one year | 617 | 252 | ||
Accounts payable | 474 | 379 | ||
Accrued expenses | 238 | 295 | ||
Payables to affiliates | 61 | 97 | ||
Customer deposits | 133 | 136 | ||
Regulatory liabilities | 171 | 170 | ||
Mark-to-market derivative liabilities | 16 | 18 | ||
Mark-to-market derivative liabilities with affiliate | 0 | 226 | ||
Other | 84 | 82 | ||
Total current liabilities | 1,947 | 1,655 | ||
Long-term debt | 5,057 | 5,315 | ||
Long-term debt of variable financing trusts | 206 | 206 | ||
Deferred credits and other liabilities | ' | ' | ||
Deferred income taxes and unamortized investment tax credits | 4,057 | 4,272 | ||
Asset retirement obligations | 99 | 99 | ||
Non-pension postretirement benefit obligations | 354 | 273 | ||
Regulatory liabilities | 3,393 | 3,229 | ||
Mark-to-market derivative liabilities | 106 | 49 | ||
Other | 994 | 484 | ||
Total deferred credits and other liabilities | 9,003 | 8,406 | ||
Total liabilities | 16,213 | 15,582 | ||
Commitments and contingencies | 0 | 0 | ||
Shareholders' equity | ' | ' | ||
Common stock | 1,588 | 1,588 | ||
Other paid-in capital | 5,189 | 5,014 | ||
Retained earnings | 696 | 721 | ||
Accumulated other comprehensive income (loss), net | 0 | 0 | ||
Total shareholders' equity | 7,473 | 7,323 | ||
Total liabilities and shareholders' equity | 23,686 | 22,905 | ||
Member's equity | ' | ' | ||
Accumulated other comprehensive income (loss), net | 0 | 0 | ||
Commonwealth Edison Co [Member] | Removal Costs [Member] | ' | ' | ||
Current liabilities | ' | ' | ||
Regulatory liabilities | 82 | 75 | ||
Deferred credits and other liabilities | ' | ' | ||
Regulatory liabilities | 1,202 | 1,192 | ||
PECO Energy Co [Member] | ' | ' | ||
Current assets | ' | ' | ||
Cash and cash equivalents | 609 | 362 | ||
Restricted cash and cash equivalents | 1 | ' | ||
Accounts receivable, net | ' | ' | ||
Customer | 250 | 364 | ||
Other | 116 | 161 | ||
Inventories, net | ' | ' | ||
Fossil fuel | 58 | 65 | ||
Materials and supplies | 21 | 19 | ||
Deferred income taxes | 48 | 40 | ||
Receivable from Exelon intercompany money pool | 1 | ' | ||
Prepaid utility taxes | 38 | 21 | ||
Regulatory assets | 22 | 32 | ||
Other | 46 | 30 | ||
Total current assets | 1,210 | 1,094 | ||
Property, plant and equipment, net | 6,270 | 6,078 | ||
Deferred debits and other assets | ' | ' | ||
Regulatory assets | 1,419 | 1,378 | ||
Investments | 22 | 22 | ||
Investments in affiliates | 8 | 8 | ||
Receivable from affiliate | 410 | 360 | ||
Prepaid pension asset | 368 | 373 | ||
Other | 38 | 40 | ||
Total deferred debits and other assets | 2,265 | 2,181 | ||
Total assets | 9,745 | 9,353 | ||
Current liabilities | ' | ' | ||
Short-term notes payable - accounts receivable agreement | ' | 210 | ||
Long-term debt due within one year | 300 | 300 | ||
Accounts payable | 249 | 244 | ||
Accrued expenses | 91 | 82 | ||
Payables to affiliates | 51 | 76 | ||
Customer deposits | 49 | 51 | ||
Regulatory liabilities | 111 | 169 | ||
Other | 28 | 26 | ||
Total current liabilities | 879 | 1,158 | ||
Long-term debt | 2,196 | 1,647 | ||
Long-term debt of variable financing trusts | 184 | 184 | ||
Deferred credits and other liabilities | ' | ' | ||
Deferred income taxes and unamortized investment tax credits | 2,440 | 2,331 | ||
Asset retirement obligations | 29 | 29 | ||
Non-pension postretirement benefit obligations | 301 | 284 | ||
Regulatory liabilities | 592 | 538 | ||
Other | 105 | 113 | ||
Total deferred credits and other liabilities | 3,467 | 3,295 | ||
Total liabilities | 6,726 | 6,284 | ||
Preferred securities | ' | 87 | ||
Shareholders' equity | ' | ' | ||
Common stock | 2,388 | 2,388 | ||
Retained earnings | 630 | 593 | ||
Accumulated other comprehensive income (loss), net | 1 | [1] | 1 | [1] |
Total shareholders' equity | 3,019 | 2,982 | ||
Total liabilities and shareholders' equity | 9,745 | 9,353 | ||
Member's equity | ' | ' | ||
Accumulated other comprehensive income (loss), net | 1 | [1] | 1 | [1] |
PECO Energy Co [Member] | Removal Costs [Member] | ' | ' | ||
Current liabilities | ' | ' | ||
Regulatory liabilities | ' | 0 | ||
Deferred credits and other liabilities | ' | ' | ||
Regulatory liabilities | ' | 0 | ||
Baltimore Gas and Electric Company [Member] | ' | ' | ||
Current assets | ' | ' | ||
Cash and cash equivalents | 7 | 89 | ||
Restricted cash and cash equivalents | 0 | ' | ||
Restricted cash and investments of variable interest entity | 50 | 30 | ||
Accounts receivable, net | ' | ' | ||
Customer | 404 | 409 | ||
Other | 132 | 111 | ||
Income taxes receivable | 0 | 3 | ||
Inventories, net | ' | ' | ||
Fossil fuel | 61 | 51 | ||
Materials and supplies | 36 | 31 | ||
Deferred income taxes | 5 | 1 | ||
Prepaid utility taxes | 76 | 57 | ||
Regulatory assets | 184 | 190 | ||
Other | 7 | 8 | ||
Total current assets | 962 | 980 | ||
Property, plant and equipment, net | 5,713 | 5,498 | ||
Deferred debits and other assets | ' | ' | ||
Regulatory assets | 509 | 522 | ||
Investments | 5 | 5 | ||
Investments in affiliates | 8 | 8 | ||
Prepaid pension asset | 434 | 467 | ||
Other | 26 | 26 | ||
Total deferred debits and other assets | 982 | 1,028 | ||
Total assets | 7,657 | 7,506 | ||
Current liabilities | ' | ' | ||
Short-term borrowings | 40 | 0 | ||
Long-term debt due within one year | 0 | 400 | ||
Long-term debt of variable interest entities due within one year | 69 | 67 | ||
Accounts payable | 184 | 195 | ||
Accrued expenses | 127 | 106 | ||
Payables to affiliates | 54 | 65 | ||
Deferred income taxes | 9 | 0 | ||
Customer deposits | 72 | 71 | ||
Regulatory liabilities | 31 | 29 | ||
Other | 58 | 47 | ||
Total current liabilities | 644 | 980 | ||
Long-term debt | 1,746 | 1,446 | ||
Long-term debt of variable financing trusts | 258 | 258 | ||
Long-term debt of variable interest entity | 230 | 265 | ||
Deferred credits and other liabilities | ' | ' | ||
Deferred income taxes and unamortized investment tax credits | 1,759 | 1,658 | ||
Asset retirement obligations | 7 | 8 | ||
Non-pension postretirement benefit obligations | 221 | 229 | ||
Regulatory liabilities | 218 | 214 | ||
Other | 66 | 90 | ||
Total deferred credits and other liabilities | 2,271 | 2,199 | ||
Total liabilities | 5,149 | 5,148 | ||
Commitments and contingencies | 0 | 0 | ||
Shareholders' equity | ' | ' | ||
Common stock | 1,360 | 1,360 | ||
Retained earnings | 958 | 808 | ||
Total shareholders' equity | 2,318 | 2,168 | ||
BGE preference stock not subject to mandatory redemption | 190 | 190 | ||
Total equity | 2,508 | 2,358 | ||
Total liabilities and shareholders' equity | 7,657 | 7,506 | ||
Baltimore Gas and Electric Company [Member] | Removal Costs [Member] | ' | ' | ||
Current liabilities | ' | ' | ||
Regulatory liabilities | 21 | 22 | ||
Deferred credits and other liabilities | ' | ' | ||
Regulatory liabilities | $218 | $214 | ||
[1] | (a) All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income. |
Consolidated_Balance_Sheets_Un1
Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
In Millions, except Share data, unless otherwise specified | ||
Accounts Receivable [Abstract] | ' | ' |
Gross accounts receivable pledged as collateral | $0 | $289 |
Shareholders' equity | ' | ' |
Common stock, par value | ' | ' |
Common stock, shares authorized | 2,000,000,000 | 2,000,000,000 |
Common stock, shares outstanding | 856,563,385 | 855,000,000 |
Treasury Stock, Shares held | 35,000,000 | 35,000,000 |
PECO Energy Co [Member] | ' | ' |
Accounts Receivable [Abstract] | ' | ' |
Gross accounts receivable pledged as collateral | ' | $289 |
Consolidated_Statement_of_Chan
Consolidated Statement of Changes in Shareholders Equity (Unaudited) (USD $) | Total | Common Stock [Member] | Nonredeemable Preferred Stock [Member] | Treasury Stock | Retained Earnings | Retained Earnings | Accumulated Other Comprehensive (Loss) Income, Net | Noncontrolling Interest | Preference Stock Not Subject To Mandatory Redemption [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | 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 | Cumulative Preferred Stock [Member] | Undistributed Earnings [Member] | Membership Interest [Member] | Accumulated Other Comprehensive (Loss) Income, Net | Noncontrolling Interest | Common Stock [Member] | Retained Earnings | Accumulated Other Comprehensive (Loss) Income, Net | Common Stock [Member] | Other Paid-In Capital | Retained Deficit Unappropriated | Retained Earnings Appropriated | Common Stock [Member] | Nonredeemable Preferred Stock [Member] | Retained Earnings | ||||||||||||||
Beginning Balance at Dec. 31, 2012 | $21,431 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $2,982 | $2,388 | $593 | $1 | $7,323 | $1,588 | $5,014 | ($1,639) | $2,360 | $2,168 | $1,360 | $190 | $808 | ||
Beginning Balance at Dec. 31, 2012 | 21,730 | 16,632 | ' | -2,327 | 9,893 | ' | -2,767 | 106 | 193 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,358 | ' | ' | ' | ||
Beginning Balance at Dec. 31, 2012 | ' | 889,525 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Beginning Balance at Dec. 31, 2012 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 12,665 | 3,168 | 8,876 | 513 | 108 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Net income | 1,235 | ' | ' | ' | 1,224 | ' | ' | -6 | 17 | 795 | 801 | ' | ' | -6 | 292 | ' | 292 | ' | 140 | ' | ' | 140 | ' | 160 | ' | ' | 160 | ||
Net income on common stock | 1,224 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 285 | ' | ' | ' | ' | ' | ' | ' | ' | 150 | ' | ' | ' | ||
Long-term incentive plan activity | ' | 2,122 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Appropriation of retained earnings for future dividends | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -140 | 140 | ' | ' | ' | ' | ||
Long-term incentive plan activity | 84 | 84 | ' | 0 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Common stock dividends | -986 | ' | ' | ' | -986 | ' | ' | ' | ' | ' | ' | ' | ' | ' | -248 | ' | -248 | ' | -165 | ' | ' | ' | -165 | ' | ' | ' | ' | ||
Common stock issuance - Constellation merger - Shares | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Common stock issuance - Constellation merger - Value | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Contribution from parent | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | 0 | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Distribution to members | ' | ' | ' | ' | ' | ' | ' | ' | ' | -550 | -550 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Allocation of tax benefit from members | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Preferred stock redemption premium | -6 | ' | -6 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -6 | ' | -6 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Allocation of tax benefit from parent | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 175 | ' | 175 | ' | ' | ' | ' | ' | ' | ||
Consolidated VIE dividend to non-controlling interest | -63 | ' | ' | ' | ' | ' | ' | -63 | ' | -63 | ' | ' | ' | -63 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Preferred security dividends | -11 | ' | ' | ' | 0 | ' | ' | ' | -11 | ' | ' | ' | ' | ' | -1 | ' | -1 | ' | ' | ' | ' | ' | ' | -10 | ' | -10 | ' | ||
Other comprehensive income (loss), net of tax | 106 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | -270 | [1] | ' | ' | -270 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Sale of noncontrolling interest | ' | ' | ' | ' | ' | ' | ' | ' | ' | -3 | ' | -3 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
ImpairmentOfLongLivedAssetsToBeDisposedOf | -4 | ' | ' | ' | ' | ' | ' | -4 | ' | -4 | ' | ' | ' | -4 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Deconsolidation of VIE | -18 | ' | ' | ' | ' | ' | ' | -18 | ' | -19 | ' | -1 | ' | -18 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Ending Balance at Sep. 30, 2013 | 21,859 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,019 | 2,388 | 630 | 1 | 7,473 | 1,588 | 5,189 | -1,639 | 2,335 | 2,318 | 1,360 | 190 | 958 | ||
Ending Balance at Sep. 30, 2013 | 22,067 | 16,716 | ' | -2,327 | 10,131 | ' | -2,661 | 15 | 193 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,508 | ' | ' | ' | ||
Ending Balance at Sep. 30, 2013 | ' | 891,647 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Ending Balance at Sep. 30, 2013 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 12,551 | 3,419 | 8,872 | 243 | 17 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Beginning Balance at Jun. 30, 2013 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Net income | 736 | ' | ' | ' | ' | ' | ' | ' | ' | 485 | ' | ' | ' | ' | 92 | ' | ' | ' | 126 | ' | ' | ' | ' | 53 | ' | ' | ' | ||
Net income on common stock | 738 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 92 | ' | ' | ' | ' | ' | ' | ' | ' | 50 | ' | ' | ' | ||
Preferred stock redemption premium | ' | ' | ' | ' | ' | -6 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Other comprehensive income (loss), net of tax | 12 | ' | ' | ' | ' | ' | ' | ' | ' | -32 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Ending Balance at Sep. 30, 2013 | 21,859 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,019 | 2,388 | ' | 1 | 7,473 | 1,588 | ' | ' | ' | 2,318 | 1,360 | ' | ' | ||
Ending Balance at Sep. 30, 2013 | 22,067 | ' | ' | ' | ' | ' | -2,661 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,508 | ' | ' | ' | ||
Ending Balance at Sep. 30, 2013 | ' | ' | ' | ' | ' | ' | ' | ' | ' | $12,551 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
[1] | (a) All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income. |
Consolidated_Statement_of_Chan1
Consolidated Statement of Changes in Shareholders Equity (Unaudited) (Parenthetical) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Other comprehensive income, income taxes | $1 | ($59) | $70 | $87 |
Accumulated Other Comprehensive (Loss) Income, Net | ' | ' | ' | ' |
Other comprehensive income, income taxes | ' | ' | 70 | ' |
Exelon Generation Co L L C [Member] | ' | ' | ' | ' |
Other comprehensive income, income taxes | -27 | -102 | -177 | -107 |
Exelon Generation Co L L C [Member] | Accumulated Other Comprehensive (Loss) Income, Net | ' | ' | ' | ' |
Other comprehensive income, income taxes | ' | ' | $177 | ' |
Basis_of_Presenation_Exelon_Ge
Basis of Presenation (Exelon, Generation, Come, PECO and BGE) | 9 Months Ended |
Sep. 30, 2013 | |
Significant Accounting Policies [Line Items] | ' |
Basis of Presentation (Exelon, Generation, ComEd, PECO and BGE) | ' |
1. Basis of Presentation (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, wholly owned 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 (the “Merger Agreement”). As a result of the merger transaction, Generation now includes the former Constellation generation and customer supply operations. BGE, formerly Constellation's regulated utility subsidiary, is now a subsidiary of Exelon. Refer to Note 4 - Merger and Acquisitions for further information regarding the merger transaction. | |
The energy generation business includes: | |
Generation: Physical delivery and marketing of owned and contracted electric generation capacity and provision of renewable and other energy-related products and services, and natural gas exploration and production activities. Generation has six reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and Other regions. | |
The energy delivery businesses include: | |
ComEd: Purchase and regulated retail sale of electricity and the provision of distribution and transmission services in northern Illinois, including the City of Chicago. | |
PECO: Purchase and regulated retail sale of electricity and the provision of distribution and transmission services in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and the provision of distribution services in the Pennsylvania counties surrounding the City of Philadelphia. | |
BGE: Purchase and regulated retail sale of electricity and the provision of distribution and transmission services in central Maryland, including the City of Baltimore, and the purchase and regulated retail sale of natural gas and the provision of distribution services in central Maryland, including the City of Baltimore. | |
For financial statement purposes, beginning on March 12, 2012, disclosures that solely relate to Constellation or BGE activities now also apply to Exelon, unless otherwise noted. 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. As a result, BGE continues to maintain its reporting requirements as an SEC registrant. The information disclosed for BGE represents the activity of the standalone entity for the three and nine months ended September 30, 2013 and 2012 and the financial position as of September 30, 2013 and December 31, 2012. However, for Exelon's financial reporting, Exelon is reporting BGE activity for the three and nine months ended September 30, 2013 and from March 12, 2012 through September 30, 2012 and the financial position as of September 30, 2013 and December 31, 2012. | |
Each of the Registrant's Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated. | |
For the nine months ended September 30, 2013, BGE recorded a $2 million correcting adjustment to decrease amortization expense related to regulatory assets that were originally recorded during 2012 and a $4 million correcting adjustment to decrease operating and maintenance expense for an overstatement of BGE's life insurance obligation related to post-employment benefits in prior years. Exelon and BGE have concluded that these correcting adjustments are not material to their respective results of operations or cash flows for the nine months ended September 30, 2013 or any prior period presented. Exelon and BGE do not expect these correcting adjustments to have a material impact on their respective results of operations or cash flows for the year ended December 31, 2013. | |
The accompanying consolidated financial statements as of September 30, 2013 and 2012 and for the three and nine months then ended are unaudited but, in the opinion of the management of each Registrant include all adjustments that are considered necessary for a fair statement of the Registrants' respective financial statements in accordance with GAAP. All adjustments are of a normal, recurring nature, except as otherwise disclosed. The December 31, 2012 Consolidated Balance Sheets were obtained from audited financial statements. Certain prior year amounts in Exelon's and BGE's Consolidated Statements of Cash Flows, Exelon's, Generation's and BGE's Consolidated Statements of Operations and Comprehensive Income and in Exelon's, Generation's, ComEd's, and BGE's Consolidated Balance Sheets have been reclassified between line items for comparative purposes. To conform to Exelon's Statement of Cash Flows presentation, BGE recorded an adjustment to its Consolidated Statement of Cash Flows for the nine months ended September 30, 2012 to reflect the change in operating cash flows and capital expenditures related to amounts not paid of approximately $17 million. The reclassifications did not materially affect any of the Registrants' net income or cash flows from operating activities. Financial results for interim periods are not necessarily indicative of results that may be expected for any other interim period or for fiscal year ended December 31, 2013. These Combined Notes to Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. These notes should be read in conjunction with the Notes to Combined Consolidated Financial Statements of all Registrants included in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA of their respective 2012 Form 10-K Reports. |
New_Accounting_Pronouncements_
New Accounting Pronouncements (Exelon, Generation, ComEd, PECO and BGE) | 9 Months Ended |
Sep. 30, 2013 | |
New Accounting Pronouncements And Changes In Accounting Principles [Line Items] | ' |
Schedule Of New Accounting Pronouncements And Changes In Accounting Principles (Exelon, Generation, ComEd, PECO and BGE) | ' |
2. New Accounting Pronouncements (Exelon, Generation, ComEd, PECO and BGE) | |
The following recently issued accounting standards were adopted by or are effective for the Registrants during 2013. | |
Presentation of Items Reclassified out of Accumulated Other Comprehensive Income | |
In February 2013, the FASB issued authoritative guidance requiring entities to present either in the notes or parenthetically on the face of the financial statements, reclassifications from each component of accumulated other comprehensive income and the affected income statement line items. Entities only need to disclose the affected income statement line item for components reclassified to net income in their entirety; otherwise, a cross-reference to the related note should be provided. This guidance was effective for the Registrants for periods beginning after December 15, 2012 and was required to be applied prospectively. As this guidance provides only disclosure requirements, the adoption of this standard did not impact the Registrants' results of operations, cash flows or financial positions. See Note 16 – Changes in Accumulated Other Comprehensive Income for the new disclosures. | |
Disclosures About Offsetting Assets and Liabilities | |
In December 2011, the FASB issued (and amended in January 2013), authoritative guidance requiring entities to disclose both gross and net information about recognized derivative instruments, including bifurcated embedded derivatives, repurchase and reverse repurchase agreements, and securities borrowing or lending transactions that are offset on the balance sheet or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset on the balance sheet. This guidance was effective for the Registrants for periods beginning on or after January 1, 2013 and is required to be applied retrospectively. This guidance is primarily applicable to certain derivative transactions for Exelon and Generation. As this guidance provides only disclosure requirements, the adoption of this standard did not impact the Registrants' results of operations, cash flows or financial positions. See Note 10 – Derivative Financial Instruments for the new disclosures. | |
Inclusion of the Fed Funds Effective Swap Rate as a Benchmark Interest Rate for Hedge Accounting Purposes | |
In July 2013, the FASB issued authoritative guidance permitting entities to designate the Fed Funds Effective Swap Rate as a U.S. benchmark interest rate for hedge accounting purposes. Prior to the issuance of this guidance, only interest rates on direct treasury obligations of the U.S. government and the LIBOR swap rate were considered benchmark interest rates in the U.S. This guidance was effective immediately and can be applied prospectively for qualifying new or redesignated hedging relationships entered into on or after July 17, 2013. Currently, the Registrants do not use the Fed Funds Effective Swap Rate as a benchmark interest rate, but may in the future. | |
The following recently issued accounting standards are not yet required to be reflected in the combined financial statements of the Registrants. | |
Presentation of Unrecognized Tax Benefits When Net Operating Loss Carryforwards, Similar Tax Losses or Tax Credit Carryforwards Exist | |
In July 2013, the FASB issued authoritative guidance requiring entities to present unrecognized tax benefits as a reduction to deferred tax assets for losses or other tax carryforwards that would be available to offset the uncertain tax positions at the reporting date. Currently, the Registrants present their unrecognized tax benefits as liabilities on a gross basis unless an unrecognized tax benefit is directly associated with a tax position taken in a tax year that results in the recognition of a net operating loss or other tax carryforward for that year. This guidance is effective for the Registrants for periods beginning after December 15, 2013 and is required to be applied prospectively, with retroactive application permitted. The Registrants are currently assessing the impacts this guidance may have on their financial positions and cash flows. The adoption of this standard will not impact the Registrants' results of operations. | |
Variable_Interest_Entities_Exe
Variable Interest Entities (Exelon, Generation, ComEd, PECO and BGE) | 9 Months Ended | ||||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||||
Variable Interest Entities Disclosure [Line Items] | ' | ||||||||||||||||||
Variable Interest Entities (Exelon, Generation, ComEd, PECO and BGE) | ' | ||||||||||||||||||
3. Variable Interest Entities (Exelon, Generation, ComEd, PECO and BGE) | |||||||||||||||||||
Under the applicable authoritative guidance, a VIE is a legal entity that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or equity owners who do not have the obligation to absorb expected losses or the right to receive the expected residual returns of the entity. Companies are required to consolidate a VIE if they are its primary beneficiary, which is the enterprise that has the power to direct the activities that most significantly impact the entity's economic performance. | |||||||||||||||||||
As of September 30, 2013 and December 31, 2012, the Registrants' consolidated four and five VIEs or VIE groups, respectively, for which the Registrants were the primary beneficiary and the Registrants had significant interests in seven and nine other VIEs for which the Registrants do not have the power to direct the entities' activities, respectively, and, accordingly, were not the primary beneficiary. | |||||||||||||||||||
Consolidated Variable Interest Entities | |||||||||||||||||||
Exelon, Generation and BGE's consolidated VIEs consist of: | |||||||||||||||||||
BondCo, a special purpose bankruptcy remote limited liability company formed by BGE to acquire, hold, and issue and service bonds secured by rate stabilization property; | |||||||||||||||||||
a retail gas group formed to enter into a collateralized gas supply agreement with a third-party gas supplier; | |||||||||||||||||||
a group of solar project limited liability companies formed to build, own and operate solar power facilities, and, | |||||||||||||||||||
several wind project companies designed to develop, construct and operate wind generation facilities. | |||||||||||||||||||
As of September 30, 2013, ComEd and PECO do not have any consolidated VIEs. | |||||||||||||||||||
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. In the case of BondCo, BGE is required to remit all payments it receives from all residential customers through non-bypassable, rate stabilization charges to BondCo. During the three and nine months ended September 30, 2013, BGE remitted $24 million and $63 million, respectively, to BondCo. During the three and nine months ended September 30, 2012, BGE remitted $27 million and $62 million, respectively, to BondCo. | |||||||||||||||||||
Except for providing capital funding to the solar entities for ongoing construction of the solar power facilities and a $75 million parental guarantee to the third-party gas supplier in support of the retail gas group, during the nine months ended September 30, 2013 and year ended December 31, 2012: | |||||||||||||||||||
Exelon, Generation and BGE did not provide any additional financial support to the VIEs; | |||||||||||||||||||
Exelon, Generation and BGE did not have any 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. | |||||||||||||||||||
The carrying amounts and classification of the consolidated VIEs' assets and liabilities included in Exelon's, Generation's, and BGE's consolidated financial statements at September 30, 2013 and December 31, 2012 are as follows: | |||||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||||
Exelon (a)(b) | Generation (b) | BGE | Exelon (a)(b)(c) | Generation (b)(c) | BGE | ||||||||||||||
Current assets | $ | 391 | $ | 330 | $ | 50 | $ | 550 | $ | 519 | $ | 30 | |||||||
Noncurrent assets | 1,900 | 1,877 | 3 | 1,802 | 1,762 | - | |||||||||||||
Total assets | $ | 2,291 | $ | 2,207 | $ | 53 | $ | 2,352 | $ | 2,281 | $ | 30 | |||||||
Current liabilities | $ | 453 | $ | 366 | $ | 77 | $ | 685 | $ | 613 | $ | 71 | |||||||
Noncurrent liabilities | 859 | 608 | 230 | 837 | 532 | 265 | |||||||||||||
Total liabilities | $ | 1,312 | $ | 974 | $ | 307 | $ | 1,522 | $ | 1,145 | $ | 336 | |||||||
_______________________ | |||||||||||||||||||
Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity. | |||||||||||||||||||
Includes total liabilities of $53 million as of September 30, 2013 and total assets of $116 million and total liabilities of $62 million as of December 31, 2012 related to deferred and accrued taxes that have been recorded and are not restricted for use by three of the consolidated VIEs. | |||||||||||||||||||
Includes total assets of $146 million and total liabilities of $42 million as of December 31, 2012 related to a retail power supply company that is no longer a consolidated VIE as of September 30, 2013. | |||||||||||||||||||
In August 2013, Generation executed an agreement to terminate its energy supply contract with a retail power supply company that was previously a consolidated VIE. Generation did not have an ownership interest in the entity, but was the primary beneficiary through the energy supply contract. As a result of the termination, Generation no longer has a variable interest in the retail power supply company and ceased consolidation of the entity during the third quarter of 2013. Upon deconsolidation, there was no gain or loss recognized. The assets, liabilities, and non-controlling interest were removed from Generation's balance sheet and the change in non-controlling interest is also reflected on the Statement of Changes in Shareholders' Equity. | |||||||||||||||||||
Unconsolidated Variable Interest Entities | |||||||||||||||||||
Exelon's and Generation's variable interests in unconsolidated VIEs generally include three transaction types: (1) equity method investments, (2) energy purchase and sale contracts, and (3) fuel purchase commitments. For the equity method investments, the carrying amount of the investments is reflected on their Consolidated Balance Sheets in Investments in affiliates. For the energy purchase and sale contracts and the fuel purchase commitments (commercial agreements), the carrying amount of assets and liabilities in Exelon's and Generation's Consolidated Balance Sheets that relate to their involvement with the VIEs are predominately related to working capital accounts and generally represent the amounts owed by, or owed to, Exelon and Generation for the deliveries associated with the current billing cycles under the commercial agreements. Further, Exelon and Generation have not provided material debt or equity support, liquidity arrangements or performance guarantees associated with these commercial agreements. | |||||||||||||||||||
The Registrants' unconsolidated VIEs consist of: | |||||||||||||||||||
Energy purchase and sale agreements with VIEs for which Generation has concluded that consolidation is not required. | |||||||||||||||||||
ZionSolutions, LLC asset sale agreement with EnergySolutions, Inc. and certain subsidiaries in which Generation has a variable interest but has concluded that consolidation is not required. | |||||||||||||||||||
Fuel purchase commitments where Generation has a variable interest, but the variable interest is not significant and Generation is not the primary beneficiary, thus consolidation is not required. | |||||||||||||||||||
ComEd's, PECO's and BGE's retail operations frequently include the purchase of electricity and RECs through procurement contracts of varying durations. None of ComEd, PECO or BGE considers itself the primary beneficiary of any VIEs as a result of these commercial arrangements. | |||||||||||||||||||
Investment in energy development projects for which Generation has concluded that consolidation is not required. | |||||||||||||||||||
As of September 30, 2013 and December 31, 2012, Exelon and Generation had significant unconsolidated variable interests in seven and nine, respectively, VIEs for which they were not the primary beneficiary; including certain equity method investments and certain commercial agreements. The change in the number of unconsolidated variable interests is driven by the completion of certain obligations which cause the entities to no longer be unconsolidated variable interests. The following tables present summary information about the significant unconsolidated VIE entities: | |||||||||||||||||||
Equity | |||||||||||||||||||
Commercial | Method | ||||||||||||||||||
Agreement | Investment | ||||||||||||||||||
30-Sep-13 | VIEs | VIEs | Total | ||||||||||||||||
Total assets (a) | $ | 115 | $ | 366 | $ | 481 | |||||||||||||
Total liabilities (a) | 3 | 126 | 129 | ||||||||||||||||
Registrants' ownership interest (a) | 0 | 97 | 97 | ||||||||||||||||
Other ownership interests (a) | 112 | 143 | 255 | ||||||||||||||||
Registrants' maximum exposure to loss: | |||||||||||||||||||
Carrying amount of equity method investments | 0 | 78 | 78 | ||||||||||||||||
Contract intangible asset | 9 | 0 | 9 | ||||||||||||||||
Debt and payment guarantees | 0 | 5 | 5 | ||||||||||||||||
Net assets pledged for Zion Station decommissioning (b) | 43 | 0 | 43 | ||||||||||||||||
Equity | |||||||||||||||||||
Commercial | Method | ||||||||||||||||||
Agreement | Investment | ||||||||||||||||||
31-Dec-12 | VIEs | VIEs | Total | ||||||||||||||||
Total assets (a) | $ | 386 | $ | 354 | $ | 740 | |||||||||||||
Total liabilities (a) | 219 | 114 | 333 | ||||||||||||||||
Registrants' ownership interest (a) | 0 | 97 | 97 | ||||||||||||||||
Other ownership interests (a) | 167 | 143 | 310 | ||||||||||||||||
Registrants' maximum exposure to loss: | |||||||||||||||||||
Letters of credit | 5 | 0 | 5 | ||||||||||||||||
Carrying amount of equity method investments | 0 | 77 | 77 | ||||||||||||||||
Contract intangible asset | 8 | 0 | 8 | ||||||||||||||||
Debt and payment guarantees | 0 | 5 | 5 | ||||||||||||||||
Net assets pledged for Zion Station decommissioning (b) | 50 | 0 | 50 | ||||||||||||||||
These items represent amounts on the unconsolidated VIE balance sheets, not on Exelon's or Generation's Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs. | |||||||||||||||||||
These items represent amounts on Exelon's and Generation's Consolidated Balance Sheets related to the asset sale agreement with ZionSolutions, LLC. The net assets pledged for Zion Station decommissioning includes gross pledged assets of $486 million and $614 million as of September 30, 2013 and December 31, 2012, respectively; offset by payables to ZionSolutions LLC of $443 million and $564 million as of September 30, 2013 and December 31, 2012, 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 assess the risk of a loss equal to their maximum exposure to be remote and, accordingly Exelon and Generation have not recognized a liability associated with any portion of the maximum exposure to loss. In addition, there are no agreements with, or commitments by, third parties that would affect the fair value or risk of their variable interests in these variable interest entities. | |||||||||||||||||||
Merger_and_Acquisitions_Exelon
Merger and Acquisitions (Exelon, Generation, ComEd, PECO and BGE) | 9 Months Ended | ||||||||||||||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||||||||||||||
Acquisitions [Line Items] | ' | ||||||||||||||||||||||||||||
Mergers and Acquisitions (Exelon, Generation, ComEd, PECO and BGE) | ' | ||||||||||||||||||||||||||||
4. Merger and Acquisitions | |||||||||||||||||||||||||||||
Merger with Constellation (Exelon, Generation, ComEd, PECO and BGE) | |||||||||||||||||||||||||||||
Description of Transaction | |||||||||||||||||||||||||||||
On March 12, 2012, Exelon completed the merger contemplated by the Merger Agreement among Exelon, Bolt Acquisition Corporation, a wholly owned subsidiary of Exelon (Merger Sub), and Constellation. As a result of that merger, Merger Sub was merged into Constellation (the Initial Merger) and Constellation became a wholly owned subsidiary of Exelon. Following the completion of the Initial Merger, Exelon and Constellation completed a series of internal corporate organizational restructuring transactions. Constellation merged with and into Exelon, with Exelon continuing as the surviving corporation (the Upstream Merger). Simultaneously with the Upstream Merger, Constellation's interest in RF HoldCo LLC, which holds Constellation's interest in BGE, was transferred to Exelon Energy Delivery Company, LLC, a wholly owned subsidiary of Exelon that also owns Exelon's interests in ComEd and PECO. Following the Upstream Merger and the transfer of RF HoldCo LLC, Exelon contributed to Generation certain subsidiaries, including those with generation and customer supply operations that were acquired from Constellation as a result of the Initial Merger and the Upstream Merger. | |||||||||||||||||||||||||||||
Regulatory Matters | |||||||||||||||||||||||||||||
In February 2012, the MDPSC issued an Order approving the Exelon and Constellation merger. As part of the MDPSC Order, Exelon agreed to provide a package of benefits to BGE customers, the City of Baltimore and the State of Maryland, resulting in an estimated direct investment in the State of Maryland of approximately $1 billion. | |||||||||||||||||||||||||||||
The direct investment estimate includes $95 million to $120 million relating to the construction of a headquarters building in Baltimore for Generation's competitive energy businesses. On March 20, 2013, Generation signed a 20 year lease agreement that is contingent upon the developer obtaining all required approvals, permits and financing for the construction of the building. Once required approvals are received and financing conditions are met, construction will commence and the building is expected to be ready for occupancy in approximately 2 years after building construction commences. The direct investment estimate also includes $625 million for Exelon's and Generation's commitment to develop or assist in development of 285 – 300 MWs of new generation in Maryland, expected to be completed over a period of 10 years. Such costs, which are expected to be primarily capital in nature, will be recognized as incurred. As of September 30, 2013, amounts reflected in the Exelon and Generation consolidated financial statements for these expenditure commitments were immaterial. On July 26, 2013, Generation executed an engineering procurement and construction contract to expand its Perryman, Maryland site with 120MW of new natural gas-fired generation to satisfy certain of these commitments and achievement of commercial operation is expected in 2015. See Note 18 – Commitments and Contingencies for additional information. | |||||||||||||||||||||||||||||
The MDPSC Order contemplates various options for complying with the new generation development commitments, including building or acquiring generating assets, making subsidy or compliance payments, or in circumstances in which the generation build is delayed, making liquidated damages payments. Exelon and Generation expect that the majority of these commitments will be satisfied by building or acquiring generating assets and, therefore, will be primarily capital in nature and recognized as incurred. If in the future Exelon determines that it is probable that it will make subsidy, compliance or liquidated damages payments related to the new generation development commitments, Exelon will record a liability at that time. As of September 30, 2013, it is reasonably possible that Exelon will be required to make subsidy or liquidated damages payments of approximately $40 million rather than build one of the generation projects contemplated by the commitments, given that the generation build is dependent upon the passage of legislation and other conditions that Exelon does not control. | |||||||||||||||||||||||||||||
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. In 2012, Exelon and Generation recorded a pre-tax loss of $272 million 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. | |||||||||||||||||||||||||||||
Accounting for the Merger Transaction | |||||||||||||||||||||||||||||
The fair value of Constellation's non-regulated business assets acquired and liabilities assumed was determined based on significant estimates and assumptions that are judgmental in nature, including projected future cash flows (including timing); discount rates reflecting risk inherent in the future cash flows; and future market prices. There were also judgments made to determine the expected useful lives assigned to each class of assets acquired and duration of liabilities assumed. | |||||||||||||||||||||||||||||
The financial statements of BGE do not include fair value adjustments for assets or liabilities subject to rate-setting provisions for BGE. BGE is subject to the rate-setting authority of FERC and the MDPSC and is accounted for pursuant to the accounting guidance for regulated operations. The rate-setting and cost recovery provisions currently in place for BGE provide revenue derived from costs including a return on investment of assets and liabilities included in rate base. Except for debt, fuel supply contracts and regulatory assets not earning a return, the fair values of BGE's tangible and intangible assets and liabilities subject to these rate-setting provisions are assumed to approximate their carrying values and, therefore, do not reflect any net adjustments related to these amounts. For BGE's debt, fuel supply contracts and regulatory assets not earning a return, the difference between fair value and book value of BGE's assets acquired and liabilities assumed is recorded as a regulatory asset and liability at Exelon Corporate as Exelon did not apply push-down accounting to BGE. See Note 1 – Basis of Presentation for additional information on BGE's push-down accounting treatment. Also see Note 5 – 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: | |||||||||||||||||||||||||||||
Purchase Price Allocation, excluding amortization | Exelon | Generation | |||||||||||||||||||||||||||
Current assets | $ | 4,936 | $ | 3,638 | |||||||||||||||||||||||||
Property, plant and equipment | 9,342 | 4,054 | |||||||||||||||||||||||||||
Unamortized energy contracts | 3,218 | 3,218 | |||||||||||||||||||||||||||
Other intangibles, trade name and retail relationships | 457 | 457 | |||||||||||||||||||||||||||
Investment in affiliates | 1,942 | 1,942 | |||||||||||||||||||||||||||
Pension and OPEB regulatory asset | 740 | 0 | |||||||||||||||||||||||||||
Other assets | 2,265 | 1,266 | |||||||||||||||||||||||||||
Total assets | 22,900 | 14,575 | |||||||||||||||||||||||||||
Current liabilities | 3,408 | 2,804 | |||||||||||||||||||||||||||
Unamortized energy contracts | 1,722 | 1,512 | |||||||||||||||||||||||||||
Long-term debt, including current maturities | 5,632 | 2,972 | |||||||||||||||||||||||||||
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 | |||||||||||||||||||||||||
Intangible Assets Recorded | |||||||||||||||||||||||||||||
For the power supply and fuel contracts acquired from Constellation, the difference between the contract price and the market price at the date of the merger was recognized as either an intangible asset or liability based on whether the contracts were in or out-of-the-money. The fair value amounts are amortized over the life of the contract in relation to the present value of the underlying cash flows as of the merger date. Amortization expense and income are recorded through purchased power and fuel expense or operating revenues. Exelon and Generation present separately in their Consolidated Balance Sheets the unamortized energy contract assets and liabilities for these contracts. Exelon's and Generation's amortization expense for the three and nine months ended September 30, 2013 amounted to $40 million and $372 million, respectively. Exelon's and Generation's amortization expense for the three months ended September 30, 2012 and for the period March 12, 2012 to September 30, 2012 amounted to $261 million and $794 million, respectively. In addition, Exelon Corporate has established a regulatory asset and an unamortized energy contract liability related to BGE's power supply and fuel contracts. The power supply and fuel contracts regulatory asset amortization was $19 million and $57 million for the three and nine months ended September 30, 2013, respectively, and $36 million and $80 million for the three months ended September 30, 2012 and for the period March 12, 2012 to September 30, 2012, respectively. An equally offsetting amortization of the unamortized energy contract liability has been recorded at Exelon Corporate in the Consolidated Statement of Operations. | |||||||||||||||||||||||||||||
Exelon's and Generation's amortization expense for the fair value of the Constellation trade name intangible asset for the three and nine months ended September 30, 2013 amounted to $8 million and $20 million, respectively. Exelon's and Generation's straight line amortization expense for the fair value of the Constellation trade name intangible asset for the three months ended September 30, 2012 and the period March 12, 2012 to September 30, 2012 amounted to $6 million and $14 million, respectively. The trade name intangible asset is included in deferred debits and other assets within Exelon's and Generation's Consolidated Balance Sheets. | |||||||||||||||||||||||||||||
The intangible assets for the fair value of the retail relationships are amortized as amortization expense on a straight line basis over the useful life of the underlying assets. Exelon's and Generation's straight line amortization expense for the three and nine months ended September 30, 2013 amounted to $8 million and $17 million, respectively. Exelon's and Generation's straight line amortization expense for the three months ended September 30, 2012 and the period March 12, 2012 to September 30, 2012 amounted to $2 million and $9 million, respectively. The retail relationships intangible assets are included in deferred debits and other assets within Exelon's and Generation's Consolidated Balance Sheets. | |||||||||||||||||||||||||||||
Exelon's intangible assets and liabilities acquired through the merger with Constellation included in its Consolidated Balance Sheets, along with the future estimated amortization, were as follows as of September 30, 2013: | |||||||||||||||||||||||||||||
Estimated amortization expense | |||||||||||||||||||||||||||||
Description | Weighted Average Amortization (Years) (b) | Gross | Accumulated Amortization | Net | Remainder of 2013 | 2014 | 2015 | 2016 | 2017 | 2018 and Beyond | |||||||||||||||||||
Unamortized energy contracts, net (a) | 1.5 | $ | 1,499 | $ | -1,299 | $ | 200 | $ | 79 | $ | 75 | $ | 18 | $ | -31 | $ | -21 | $ | 80 | ||||||||||
Trade name | 10 | 243 | -40 | 203 | 6 | 24 | 24 | 24 | 24 | 101 | |||||||||||||||||||
Retail relationships | 12.4 | 214 | -31 | 183 | 5 | 19 | 18 | 18 | 18 | 105 | |||||||||||||||||||
Total, net | $ | 1,956 | $ | -1,370 | $ | 586 | $ | 90 | $ | 118 | $ | 60 | $ | 11 | $ | 21 | $ | 286 | |||||||||||
Includes the fair value of BGE's power and gas supply contracts of $32 million for which an offsetting regulatory asset was also recorded. | |||||||||||||||||||||||||||||
Weighted average amortization period was calculated as of the date of acquisition. | |||||||||||||||||||||||||||||
Impact of Merger | |||||||||||||||||||||||||||||
It is impracticable to determine the overall financial statement impact for the Constellation subsidiaries contributed down to Generation following the Upstream Merger for the three and nine months ended September 30, 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 included operating revenues of $720 million and no net income during the three months ended September 30, 2012, and operating revenues of $1,388 million and net loss of $49 million during the nine months ended September 30, 2012. | |||||||||||||||||||||||||||||
During the three months ended September 30, 2013, Exelon, Generation, ComEd, PECO and BGE incurred merger and integration-related costs of $43 million, $32 million, $5 million, $3 million and $2 million, respectively. During the nine months ended September 30, 2013, Exelon, Generation, ComEd, PECO and BGE incurred merger and integration-related costs of $106 million, $75 million, $14 million, $8 million and $5 million, respectively. Of these amounts, Exelon, ComEd and BGE deferred $15 million, $10 million and $5 million, respectively, as a regulatory asset as of September 30, 2013. Additionally, Exelon and BGE established a regulatory asset of $6 million as of September 30, 2013 for previously incurred 2012 merger and integration-related costs. | |||||||||||||||||||||||||||||
During the three months ended September 30, 2012, Exelon, Generation, ComEd, PECO and BGE incurred merger and integration-related costs of $95 million, $79 million, $8 million, $3 million and $1 million, respectively. During the nine months ended September 30, 2012, Exelon, Generation, ComEd, PECO and BGE incurred merger and integration-related costs of $729 million, $283 million, $34 million, $13 million and $172 million, respectively. Of these amounts, Exelon, ComEd and BGE deferred $49 million, $30 million and $19 million, respectively, as a regulatory asset as of September 30, 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 the three and nine months ended September 30, 2012. See Note 18 – Commitments and Contingencies for additional information. | |||||||||||||||||||||||||||||
Severance Costs | |||||||||||||||||||||||||||||
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. | |||||||||||||||||||||||||||||
Upon closing the merger with Constellation, Exelon recorded a severance accrual for the anticipated employee position reductions as a result of the post-merger integration. The majority of these positions are corporate and Generation support positions. Since then, Exelon has identified specific employees to be severed pursuant to the merger-related staffing and selection process as well as employees that were previously identified for severance but have since accepted another position within Exelon and are no longer receiving a severance benefit. Exelon adjusts its accrual each quarter to reflect its best estimate of remaining severance costs. In addition, certain employees identified during the staffing and selection process also receive pension and other postretirement benefits that are deemed contractual termination benefits, which the Registrants recorded during the second quarter of 2012. | |||||||||||||||||||||||||||||
The amount of severance expense associated with the post-merger integration recognized for the three months ended September 30, 2013 for Exelon and Generation were $3 million and $3 million, respectively. For Generation, $2 million represents amounts billed by BSC through intercompany allocations. The amount of severance expense associated with the post-merger integration recognized for the nine months ended September 30, 2013 for Exelon and Generation were $6 million and $6 million, respectively. For Generation, $5 million represents amounts billed by BSC through intercompany allocations. There was no severance expense associated with post-merger integration recognized for the three and nine months ended September 30, 2013 for ComEd, PECO and BGE. Estimated costs to be incurred after September 30, 2013 are not material. | |||||||||||||||||||||||||||||
For the three and nine months ended September 30, 2012, the Registrants recorded the following severance benefits costs associated with the identified job reductions within operating and maintenance expense in their Consolidated Statements of Operations, except for ComEd and BGE: | |||||||||||||||||||||||||||||
Three Months Ended September 30, 2012 | |||||||||||||||||||||||||||||
Severance Benefits (a) | Exelon | Generation | ComEd (b) | PECO | BGE (c) | ||||||||||||||||||||||||
Severance charges | $ | 8 | $ | 4 | $ | 1 | $ | 1 | $ | 1 | |||||||||||||||||||
Stock compensation | 3 | 2 | 1 | 0 | 0 | ||||||||||||||||||||||||
Total severance benefits | $ | 11 | $ | 6 | $ | 2 | $ | 1 | $ | 1 | |||||||||||||||||||
Nine Months Ended September 30, 2012 | |||||||||||||||||||||||||||||
Severance Benefits (a) | Exelon | Generation | ComEd (b) | PECO | BGE (c) | ||||||||||||||||||||||||
Severance charges | $ | 117 | $ | 68 | $ | 16 | $ | 8 | $ | 18 | |||||||||||||||||||
Stock compensation | 6 | 4 | 1 | 0 | 0 | ||||||||||||||||||||||||
Other charges (d) | 7 | 4 | 1 | 0 | 1 | ||||||||||||||||||||||||
Total severance benefits | $ | 130 | $ | 76 | $ | 18 | $ | 8 | $ | 19 | |||||||||||||||||||
_________________ | |||||||||||||||||||||||||||||
The amounts above include $0 million and $40 million at Generation, $2 million and $16 million at ComEd, $1 million and $8 million at PECO, and $1 million and $7 million at BGE, for amounts billed by BSC through intercompany allocations for the three and nine months ended September 30, 2012, respectively. | |||||||||||||||||||||||||||||
ComEd established regulatory assets of $2 million and $18 million for severance benefits costs for the three and nine months ended September 30, 2012, respectively. The majority of these costs are expected to be recovered over a five-year period. | |||||||||||||||||||||||||||||
BGE established regulatory assets of $1 million and $19 million for severance benefits costs for the three and nine months ended September 30, 2012, respectively. The majority of these costs are being recovered over a five-year period beginning in March 2013. | |||||||||||||||||||||||||||||
(d) Primarily includes life insurance, employer payroll taxes, educational assistance and outplacement services. | |||||||||||||||||||||||||||||
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: | |||||||||||||||||||||||||||||
Nine Months Ended September 30, 2013 | |||||||||||||||||||||||||||||
Severance liability | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||||||||||
Balance at December 31, 2012 | $ | 111 | $ | 33 | $ | 1 | $ | 0 | $ | 11 | |||||||||||||||||||
Severance charges (a) | 5 | 1 | 0 | 0 | 0 | ||||||||||||||||||||||||
Stock compensation | 1 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||||
Payments | -52 | -20 | 0 | 0 | -4 | ||||||||||||||||||||||||
Balance at September 30, 2013 | $ | 65 | $ | 14 | $ | 1 | $ | 0 | $ | 7 | |||||||||||||||||||
Includes salary continuance and health and welfare severance benefits. Amounts represent ongoing severance plan benefits. | |||||||||||||||||||||||||||||
Cash payments under the plan began in the second quarter of 2012. Substantially all cash payments under the plan are expected to be made by the end of 2016. | |||||||||||||||||||||||||||||
The Registrants provide severance and health and welfare benefits under Exelon's ongoing severance benefit plans to terminated employees in the normal course of business, which are not directly related to the merger with Constellation. These benefits are accrued for when the benefits are considered probable and can be reasonably estimated. | |||||||||||||||||||||||||||||
For the three and nine months ended September 30, 2013, the Registrants recorded the following severance costs associated with these ongoing severance benefits within operating and maintenance expense in their Consolidated Statements of Operations: | |||||||||||||||||||||||||||||
Severance Benefits (a) | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||||||||||
Severance charges - three months | $ | 12 | $ | 11 | $ | 1 | $ | - | $ | - | |||||||||||||||||||
Severance charges - nine months | 14 | 12 | 2 | - | - | ||||||||||||||||||||||||
_________________ | |||||||||||||||||||||||||||||
The amounts above for Generation include $1 million for amounts billed by BSC through intercompany allocations for the three and nine months ended September 30, 2013. | |||||||||||||||||||||||||||||
For the three and nine months ended September 30, 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: | |||||||||||||||||||||||||||||
Severance Benefits (a) | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||||||||||
Severance charges - three months | $ | 5 | $ | 3 | $ | 1 | $ | - | $ | 1 | |||||||||||||||||||
Severance charges - nine months | 11 | 8 | 1 | - | 2 | ||||||||||||||||||||||||
_________________ | |||||||||||||||||||||||||||||
The amounts above for Generation include $1 million for amounts billed by BSC through intercompany allocations for the three and nine months ended September 30, 2012. | |||||||||||||||||||||||||||||
The severance liability balances associated with these ongoing severance benefits as of September 30, 2013 and December 31, 2012 are not material. | |||||||||||||||||||||||||||||
Pro-forma Impact of the Merger | |||||||||||||||||||||||||||||
The following unaudited pro forma financial information reflects the consolidated results of operations of Exelon and Generation as if the merger with Constellation had taken place on January 1, 2011. The unaudited pro forma information was calculated after applying Exelon's and Generation's accounting policies and adjusting Constellation's results to reflect purchase accounting adjustments. | |||||||||||||||||||||||||||||
The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of results of operations that would have been achieved had the merger events taken place on the dates indicated, or the future consolidated results of operations of the combined company. | |||||||||||||||||||||||||||||
Three Months Ended September 30, 2012 | |||||||||||||||||||||||||||||
Generation | Exelon | ||||||||||||||||||||||||||||
Total Revenues | $ | 4,293 | $ | 6,841 | |||||||||||||||||||||||||
Net income attributable to Exelon | 282 | 492 | |||||||||||||||||||||||||||
Basic Earnings Per Share | n.a. | $ | 0.58 | ||||||||||||||||||||||||||
Diluted Earnings Per Share | n.a. | 0.57 | |||||||||||||||||||||||||||
Nine Months Ended September 30, 2012 | |||||||||||||||||||||||||||||
Generation | Exelon | ||||||||||||||||||||||||||||
Total Revenues | $ | 12,753 | $ | 20,084 | |||||||||||||||||||||||||
Net income attributable to Exelon | 805 | 1,439 | |||||||||||||||||||||||||||
Basic Earnings Per Share | n.a. | $ | 1.79 | ||||||||||||||||||||||||||
Diluted Earnings Per Share | n.a. | 1.79 |
Regulatory_Matters_Exelon_Gene
Regulatory Matters (Exelon, Generation, ComEd, PECO and BGE) | 9 Months Ended | |||||||||||||||||||||||||||||
Sep. 30, 2013 | ||||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ' | |||||||||||||||||||||||||||||
Regulatory Matters (Exelon, Generation, ComEd, PECO and BGE) | ' | [1] | ||||||||||||||||||||||||||||
Maryland Regulatory Matters | ||||||||||||||||||||||||||||||
Smart Meter and Smart Grid Investments (Exelon and BGE). In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE that includes the planned installation of 2 million residential and commercial electric and gas smart meters at an expected total cost of $480 million. The MDPSC's approval ordered BGE to defer the associated incremental costs, depreciation and amortization, and an appropriate return, in a regulatory asset until such time as a cost-effective advanced metering system is implemented. As of September 30, 2013 and December 31, 2012, BGE recorded a regulatory asset of $52 million and $31 million, respectively, representing incremental costs, depreciation and amortization, and a debt return on fixed assets related to its AMI program. Additionally, the MDPSC has determined that the cost recovery for the non-AMI meters that BGE retires will be considered in a future depreciation proceeding. The MDPSC continues to evaluate the impacts of a customer opt-out feature in BGE's Smart Grid program. In March 2013, BGE filed a description of the overall additional costs associated with allowing customers to retain their current meter, and for radio frequency (RF)-Free and RF-Minimizing options related to the installation of their smart meters as well as a proposed cost recovery mechanism. The MDPSC held a hearing in August 2013 to consider the filings made by BGE and other Maryland electric utilities. The ultimate resolution related to this feature could affect BGE's ability to demonstrate cost-effectiveness of the advanced metering system. Overall, BGE continues to believe the recovery of smart grid initiative costs in future rates is probable as BGE expects to be able to demonstrate that the program benefits exceed costs. Pursuant to the ARRA of 2009, BGE is a recipient of $200 million in federal funding from the DOE for its smart grid and other related initiatives, which substantially reduces the total cost of these initiatives to BGE's ratepayers. The project to install the smart meters began in late April 2012. | ||||||||||||||||||||||||||||||
As of September 30, 2013, BGE had received $176 million in reimbursements from the DOE. As of September 30, 2013, BGE's outstanding receivable from the DOE for reimbursable costs was $23 million, which has been recorded in Other accounts receivable, net on Exelon's and BGE's Consolidated Balance Sheets. | ||||||||||||||||||||||||||||||
New Electric Generation (Exelon, Generation and BGE). On April 12, 2012, the MDPSC issued an order directing BGE and two other Maryland utilities to enter into a contract for differences (CfD) with CPV Maryland, LLC (CPV), under which CPV will construct an approximately 700 MW natural gas-fired combined-cycle generation plant in Waldorf, Maryland, that CPV projected will be in commercial operation by June 1, 2015. The initial term of the proposed contract is 20 years. The CfD mandates that BGE and the other utilities pay (or receive) the difference between CPV's contract prices and the revenues CPV receives for capacity and energy from clearing the unit in the PJM capacity market. The MDPSC's Order requires the three Maryland utilities to enter into a CfD in amounts proportionate to their relative SOS load. | ||||||||||||||||||||||||||||||
On April 16, 2013, the MDPSC issued an order that required BGE to execute a specific form of contract with CPV, and the parties executed the contract as of June 6, 2013. As of September 30, 2013, there is no impact on Exelon's and BGE's results of operations, cash flows and financial positions. Furthermore, the agreement does not become effective until the resolution of certain items, including all current litigation. | ||||||||||||||||||||||||||||||
On April 27, 2012, a civil complaint was filed in the U.S. District Court for the District of Maryland by certain unaffiliated parties that challenges the actions taken by the MDPSC on Federal law grounds. On October 24, 2013, the U.S. District Court issued a judgment order finding that the MDPSC's Order directing BGE and the two other Maryland utilities to enter into a CfD, which assures that CPV receives a guaranteed fixed price regardless of the price set by the federally regulated wholesale market, violates the Supremacy Clause of the United States Constitution. | ||||||||||||||||||||||||||||||
On 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. | ||||||||||||||||||||||||||||||
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. | ||||||||||||||||||||||||||||||
2012 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). On July 27, 2012, BGE filed an application for increases to its electric and gas base rates with the MDPSC. On February 22, 2013, the MDPSC issued an order in BGE's 2012 electric and natural gas distribution rate case for increases in annual distribution service revenue of $81 million and $32 million, respectively. The electric distribution rate increase was set using an allowed return on equity of 9.75% and the gas distribution rate increase was set using an allowed return on equity of 9.60%. The approved electric and natural gas distribution rates became effective for services rendered on or after February 23, 2013. As part of the rate order, the MDPSC approved both recovery of and return on merger integration costs incurred during the test year, including severance. As a result, the order affirmed the treatment of $20 million of severance-related costs that BGE had recorded as a regulatory asset in 2012, consistent with prior MDPSC decisions. Additionally, BGE established a new regulatory asset of $8 million related to non-severance merger integration costs, which includes $6 million of costs incurred during 2012. Current MDPSC treatment of these merger integration regulatory assets is to provide recovery over a five year period. | ||||||||||||||||||||||||||||||
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. | ||||||||||||||||||||||||||||||
BGE's May 17, 2013 distribution rate case included a short-term plan to improve reliability as well as a proposal for a surcharge to recover incremental capital expenditures and operating costs associated with the short-term plan. On September 3, 2013, BGE filed a comprehensive long term assessment examining potential alternatives for improving the resiliency of the electric grid and a staffing analysis reviewing historical staffing levels as well as forecasting staffing levels necessary under various storm scenarios. BGE currently cannot predict the outcome of these proceedings, which may result in increased capital expenditures and operating costs. | ||||||||||||||||||||||||||||||
The Maryland Strategic Infrastructure Development and Enhancement Program (Exelon and BGE). In February 2013, the Maryland General Assembly passed legislation intended to accelerate gas infrastructure replacements in Maryland by establishing a mechanism for gas companies to promptly recover reasonable and prudent costs of eligible infrastructure replacement projects separate from base rate proceedings. On May 2, 2013, the Governor of Maryland signed the legislation into law; which took effect June 1, 2013. Under the new law, following a proceeding before the MDPSC and with the MDPSC's approval of the eligible infrastructure replacement projects along with a corresponding surcharge, BGE could begin charging gas customers a monthly surcharge for infrastructure costs incurred after June 1, 2013. The legislation includes caps on the monthly surcharges to residential and non-residential customers, and would require an annual true-up of the surcharge revenues against actual expenditures. Investment levels in excess of the cap would be recoverable in a subsequent gas base rate proceeding at which time all costs for the infrastructure replacement projects would be rolled into gas distribution rates. Irrespective of the cap, BGE is required to file a gas rate case every five years under this legislation. On August 2, 2013, BGE filed its infrastructure replacement plan and associated surcharge. The new surcharge rates are expected to take effect in the first quarter of 2014. BGE currently cannot predict the outcome of this proceeding or how much of the requested planned and related surcharge the MDPSC will approve. | ||||||||||||||||||||||||||||||
2013 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). On May 17, 2013, BGE filed an application for increases of $101 million and $30 million to its electric and gas base rates, respectively, with the MDPSC. The requested rates of return on equity in the application are 10.50% and 10.35% for electric and gas distribution, respectively. In addition to these requested rate increases, BGE's application includes a request for recovery of incremental capital expenditures and operating costs associated with BGE's proposed short-term reliability improvement plan in response to a MDPSC order through a surcharge separate from base rates. On August 23, 2013, BGE filed an update to its rate request which altered the requested increase to electric base rates from $101 million to $83 million and the requested increase to gas base rates from $30 million to $24 million. The new electric and gas distribution base rates are expected to take effect in December 2013. BGE currently cannot predict the outcome of this proceeding or how much of the requested increases the MDPSC will approve. | ||||||||||||||||||||||||||||||
Pennsylvania Regulatory Matters | ||||||||||||||||||||||||||||||
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. | ||||||||||||||||||||||||||||||
In the second DSP Program, PECO is procuring electric supply for its default electric customers through five competitive procurements. The load for the residential and small and medium commercial classes is served through competitively procured fixed price, full requirements contracts of two years or less. For the large commercial and industrial class load, PECO has competitively procured contracts for full requirements default electric generation with the price for energy in each contract set to be the hourly price of the spot market during the term of delivery. In December 2012 and February 2013, PECO entered into contracts with PAPUC-approved bidders, including Generation, for its residential and small and medium commercial classes that began in June 2013. In September 2013, PECO entered into contracts with PAPUC-approved bidders, including Generation, for its residential and small and medium commercial classes that will begin in December 2013. Charges incurred for electric supply procured through contracts with Generation are included in purchased power from affiliates on PECO's Statement of Operations and Comprehensive Income. | ||||||||||||||||||||||||||||||
In addition, the second DSP Program includes a number of retail market enhancements recommended by the PAPUC in its previously issued Retail Markets Intermediate Work Plan Order. PECO was also directed to allow its low-income Customer Assistance Program (CAP) customers to purchase their generation supply from EGSs beginning April 2014. On May 1, 2013, PECO filed its CAP Shopping Plan with the PAPUC. | ||||||||||||||||||||||||||||||
Smart Meter and Smart Grid Investments (Exelon and PECO). Pursuant to Act 129 and the follow-on Implementation Order of 2009, in April 2010, the PAPUC approved PECO's Smart Meter Procurement and Installation Plan (SMPIP), under which PECO will install more than 1.6 million smart meters and an AMI communication network by 2020. The first phase of PECO's SMPIP, which was completed on June 19, 2013, included the installation of an AMI communications network and the deployment of 600,000 smart meters to communicate with that network. On May 31, 2013, PECO and interested parties filed a Joint Petition for Settlement of the universal deployment plan with the PAPUC which was approved without modification on August 15, 2013. The Joint Petition for Settlement supports all material aspects of PECO's universal deployment plan, including cost recovery, excluding certain amounts discussed below. Universal deployment is the second phase of PECO's SMPIP, under which PECO will deploy the remainder of the 1.6 million smart meters on an accelerated basis by the end of 2014. In total, PECO currently expects to spend up to $595 million, excluding the cost of the original meters (as further described below), on its smart meter infrastructure and approximately $120 million on smart grid investments through 2014 of which $200 million will be funded by SGIG as discussed below. As of September 30, 2013, PECO has spent $364 million and $111 million on smart meter and smart grid infrastructure, respectively, not including the DOE reimbursements received to date. | ||||||||||||||||||||||||||||||
Pursuant to the ARRA of 2009, PECO and the DOE entered into a Financial Assistance Agreement to extend PECO $200 million in non-taxable SGIG funds of which $140 million relates to smart meter deployment and $60 million relates to smart grid infrastructure. As part of the agreement, the DOE has a conditional ownership interest in qualifying Federally-funded project property and equipment, which is subordinate to PECO's existing mortgage. The SGIG funds are being used to offset the total impact to ratepayers of the smart meter deployment required by Act 129. As of September 30, 2013, PECO has received $181 million of the $200 million in reimbursements. PECO's outstanding receivable from the DOE for reimbursable costs was $6 million as of September 30, 2013, which has been recorded in Other accounts receivable, net on Exelon's and PECO's Consolidated Balance Sheets. | ||||||||||||||||||||||||||||||
On August 15, 2012, PECO suspended installation of smart meters for new customers based on a limited number of incidents involving overheating meters. Following its own internal investigation and additional scientific analysis and testing by independent experts completed after September 30, 2012, PECO announced its decision to resume meter deployment work on October 9, 2012. PECO has replaced the previously installed meters with an alternative vendor's meters. PECO is moving forward with the alternative meters during universal deployment and continues to evaluate meters from several vendors and may use more than one meter vendor during universal deployment. | ||||||||||||||||||||||||||||||
Following PECO's decision, as of October 9, 2012, PECO will no longer use the original smart meters. For the meters that will no longer be used, the accounting guidance requires that any difference between the carrying value and net realizable value be recognized in the current period's earnings, before considering potential regulatory recovery. The cost of the original meters, including installation and removal costs, owned by PECO was approximately $19 million, net of approximately $16 million of reimbursements from the DOE. PECO is seeking full recovery of all incurred costs related to the original deployment of meters. For amounts not recovered from the vendor, PECO will seek regulatory rate recovery in a future filing with the PAPUC. PECO did not seek recovery of original meter costs in the January 2013 universal deployment filing, as resolution with the vendor is still pending. PECO requested and received approval from the DOE that the original meters continue to be allowable costs and that any settlement with the vendor will not be considered project income. In addition, PECO remains eligible for the full $200 million in SGIG funds. In the May 31, 2013 Joint Petition for Settlement of the universal deployment plan, the parties agreed to defer any potential challenges to cost recovery of the original meters as discussed above. | ||||||||||||||||||||||||||||||
As of September 30, 2013, PECO believes the amounts incurred for the original meters and related installation and removal costs are probable of recovery based on applicable case law and past precedent on reasonably and prudently incurred costs. As a result, a regulatory asset of $17 million, representing the cost of the original meters, net of accumulated depreciation and DOE reimbursements, was recorded on Exelon's and PECO's Consolidated Balance Sheets. On August 15, 2013, PECO entered into an agreement with the vendor, which is anticipated to be part of a larger agreement, and under which PECO transferred the original uninstalled meters to the vendor and will receive approximately $12 million in return, of which $2 million has been received as of September 30, 2013. As a result, during the third quarter of 2013, the $17 million regulatory asset was reduced to $5 million. The agreement does not fully resolve the claim against the vendor for the original meter costs and PECO continues to seek full recovery from the vendor of all incurred costs related to the original deployment of meters. If PECO later determines that the remaining regulatory asset is no longer probable of recovery, PECO would be required to recognize a charge in earnings in the period in which that determination was made. | ||||||||||||||||||||||||||||||
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 report with the PAPUC on March 1, 2013. The final compliance report is due to the PAPUC by 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 seeks 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 PAPUC deferred a decision on peak demand reduction requirements until late 2013. On February 28, 2013, the PAPUC approved PECO's three-year EE&C Phase II plan that was filed on November 1, 2012, and 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. | ||||||||||||||||||||||||||||||
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 cost 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. | ||||||||||||||||||||||||||||||
Investigation of Pennsylvania Retail Electricity Market (Exelon and PECO). On July 28, 2011, the PAPUC issued an order outlining the next steps in its investigation into the status of competition in Pennsylvania's retail electric market. The PAPUC found that the existing default service model presents substantial impediments to the development of a vibrant retail market in Pennsylvania and directed its Office of Competitive Markets Oversight to evaluate potential intermediate and long-term structural changes to the default service model. On March 1, 2012, the PAPUC issued the final order describing more detailed recommendations to be implemented prior to the expiration of the electric distribution company's current default service plan and providing guidelines for electric distribution companies for development of their next default service plan. On October 12, 2012, the PAPUC approved PECO's second DSP Program, which includes several new programs to continue PECO's support of retail market competition in Pennsylvania in accordance with the order issued by the PAPUC on December 15, 2011. Further, the PAPUC issued a final order on February 14, 2013, outlining its proposed end-state for default service, which included default service pricing for residential and small commercial customers based on three month full requirements contracts, full requirement contracts using hourly spot market pricing for large commercial and industrial default service customers, and the inclusion of CAP customers in the customer choice programs. | ||||||||||||||||||||||||||||||
Pennsylvania Act 11 of 2012 (Exelon and PECO). On February 13, 2012, Act 11 was signed into law by the Governor. Act 11 seeks to clarify the PAPUC's authority to approve alternative ratemaking mechanisms, which would allow for the implementation of a distribution system improvement charge (DSIC) in rates designed to recover capital project costs incurred to repair, improve or replace utilities' aging electric and natural gas distribution systems in Pennsylvania. Act 11 also includes a provision that allows utilities to use a fully projected future test year under which the PAPUC may permit the inclusion of projected capital costs in rate base for assets that will be placed in service during the first year that rates are in effect. The PAPUC's 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 PAPUC 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. | ||||||||||||||||||||||||||||||
Federal Regulatory Matters | ||||||||||||||||||||||||||||||
Transmission Formula Rate (Exelon, ComEd and BGE). ComEd's and BGE's transmission rates are each established based on a FERC-approved formula. | ||||||||||||||||||||||||||||||
ComEd's most recent annual formula rate update filed in April 2013 reflects 2012 actual costs plus forecasted 2013 capital additions. The update resulted in a revenue requirement of $488 million plus a $25 million adjustment related to the reconciliation of 2012 actual costs for a net revenue requirement of $513 million. This compares to the May 2012 updated revenue requirement of $450 million offset by a $5 million reduction related to the reconciliation of 2011 actual costs for a net revenue requirement of $445 million. The increase in the revenue requirement was primarily driven by increased plant investment, higher pension and post-retirement healthcare costs, and higher operating and maintenance costs. The 2013 net revenue requirement became effective June 1, 2013, and is being recovered over the period extending through May 31, 2014. The regulatory asset associated with the true-up is being amortized as the associated amounts are recovered through rates. | ||||||||||||||||||||||||||||||
ComEd's updated formula transmission rate currently provides for a weighted average debt and equity return on transmission rate base of 8.70%, a decrease from the 8.91% return previously authorized. The decrease in return was primarily due to lower interest rates on ComEd's long-term debt outstanding. As part of the FERC-approved settlement of ComEd's 2007 transmission rate case, the rate of return on common equity is 11.5% and the common equity component of the ratio used to calculate the weighted average debt and equity return for the formula transmission rate is currently capped at 55%. | ||||||||||||||||||||||||||||||
BGE's most recent annual formula rate update filed in April 2013 reflects actual 2012 expenses and investments plus forecasted 2013 capital additions. The update resulted in a revenue requirement of $158 million offset by a $1 million reduction related to the reconciliation of 2012 actual costs for a net revenue requirement of $157 million. This compares to the April 2012 updated revenue requirement of $156 million increased by $2 million related to the reconciliation of 2011 actual costs for a net revenue requirement of $158 million. The decrease in the revenue requirement was primarily driven by a lower realized rate of return and reduced rate base, offset partially by higher depreciation and operating and maintenance costs. The 2013 net revenue requirement became effective June 1, 2013, and is being recovered over the period extending through May 31, 2014. The regulatory asset associated with the true-up is being amortized as the associated amounts are recovered through rates. | ||||||||||||||||||||||||||||||
BGE's updated formula transmission rate currently provides for a weighted average debt and equity return on transmission rate base of 8.35%, a decrease from the 8.43% return previously authorized. The decrease in return was primarily due to a debt issuance in 2012 and lower interest rates on BGE's debt outstanding. As part of the FERC-approved settlement in 2006 of BGE's 2005 transmission rate case, the base rate of return on common equity for BGE's electric transmission business for new transmission projects placed in service on and after January 1, 2006 is 11.3%, inclusive of a 50 basis point incentive for participating in PJM. | ||||||||||||||||||||||||||||||
FERC Transmission Complaint (Exelon and BGE). On February 27, 2013, consumer advocates and regulators from the District of Columbia, New Jersey, Delaware and Maryland, and the Delaware Electric Municipal Cooperatives (the parties), filed a complaint at FERC against BGE and the Pepco Holdings, Inc. companies relating to their respective transmission formula rates. BGE's formula rate includes a 10.8% base rate of return on common equity for most investments included in its rate base. The parties seek a reduction in the base return on equity to 8.7% and changes to the formula rate process. FERC docketed the matter and set April 3, 2013 as the deadline for interventions, protests and answers. Under FERC rules, the earliest date from which the base return on equity could be adjusted and refunds required is the date of the complaint. On March 19, 2013, BGE filed a motion to dismiss or sever the complaint. As of September 30, 2013, BGE cannot predict the likelihood or a reasonable estimate of the amount of a change, if any, in the allowed base return on equity, or a reasonable estimate of the refund period start date. While BGE cannot predict the outcome of this matter, if FERC orders a reduction of BGE's base return on equity from 10.8% to 8.7%, the estimated annual impact would be a reduction in revenues of approximately $10 million. | ||||||||||||||||||||||||||||||
PJM Transmission Rate Design and Operating Agreements (Exelon, ComEd, PECO and BGE). PJM Transmission Rate Design specifies the rates for transmission service charged to customers within PJM. Currently, ComEd, PECO and BGE incur costs based on the existing rate design, which charges customers based on the cost of the existing transmission facilities within their load zone and the cost of new transmission facilities based on those who benefit from those facilities. In April 2007, FERC issued an order concluding that PJM's current rate design for existing facilities is just and reasonable and should not be changed. In the same order, FERC held that the costs of new facilities 500 kV and above should be socialized across the entire PJM footprint and that the costs of new facilities less than 500 kV should be allocated to the customers of the new facilities who caused the need for those facilities. After FERC ultimately denied all requests for rehearing on all issues, several parties filed petitions in the U.S. Court of Appeals for the Seventh Circuit for review of the decision. On August 6, 2009, that court issued its decision affirming FERC's order with regard to the costs of existing facilities but reversing and remanding to FERC for further consideration its decision with regard to the costs of new facilities 500 kV and above. On March 30, 2012, FERC issued an order on remand affirming the cost allocation in its April 2007 order. On March 22, 2013, FERC issued an order denying rehearing and made it clear that the cost allocation at issue concerns only projects approved prior to February 1, 2013. A number of entities have filed appeals of the FERC orders. ComEd 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 that 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 June 30, 2006 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. | ||||||||||||||||||||||||||||||
On October 11, 2012, the PJM Transmission Owners filed with FERC a cost allocation for new transmission facilities asking that the new cost allocation methodology apply to all transmission approved by the PJM Board on or after February 1, 2013. The proposed methodology is a hybrid methodology that would socialize 50% of the costs of new facilities at 500kV and above and double-circuit 345kV lines, and allocate the remaining 50% to direct beneficiaries. For all other facilities, the costs would be allocated to the direct beneficiaries. On March 22, 2013, FERC issued an order accepting the cost allocation with minor exceptions and requiring a compliance filing on those few issues within 120 days of the order. The compliance filing was made on July 22, 2013. | ||||||||||||||||||||||||||||||
ComEd, PECO and BGE are committed to the construction of transmission facilities under their operating agreements with PJM to maintain system reliability. ComEd, PECO and BGE will work with PJM to continue to evaluate the scope and timing of any required construction projects. There were no significant changes in baseline project commitments for ComEd, PECO and BGE through the third quarter of 2013. | ||||||||||||||||||||||||||||||
PJM Minimum Offer Price Rule (Exelon and Generation). PJM's capacity market rules include a Minimum Offer Price Rule (MOPR) that is intended to preclude sellers from artificially suppressing the competitive price signals for generation capacity. The proceedings leading to FERC's approval of the MOPR were extensive, and there have been numerous changes to the MOPR and litigation related to it since it was originally implemented. For example, in 2011 the parties disputed numerous elements of the MOPR including: (i) the default price that should apply to bids found subject to the MOPR, (ii) the duration of the MOPR and (iii) the application of the MOPR to self-supplying capacity and state-sponsored capacity. The FERC orders approving that MOPR have been appealed to the United States Court of Appeals for the Third Circuit. A resolution of that appeal is not expected until sometime in late 2013. | ||||||||||||||||||||||||||||||
In May 2012 (based on the MOPR provisions the FERC approved in 2011), PJM announced the results of its capacity auction covering the delivery year ending May 31, 2016. Several new units with state-sanctioned subsidy contracts cleared in the auction at prices below the MOPR. Potentially, these states could expand such state-sanctioned subsidy programs or other states may seek to establish similar programs. Generation believed that further revisions to that MOPR were necessary to ensure that the potential to artificially reduce capacity auction prices is appropriately limited in PJM. In early December 2012, PJM filed a new MOPR for approval at the FERC, which Exelon believed would be more effective in preventing state-sanctioned subsidy contracts from artificially reducing capacity prices. Generation was actively involved in the process through which those MOPR changes were developed and supported the changes. On May 3, 2013, the FERC issued its order. While the FERC order accepted certain aspects of the proposal that Exelon supported (such as applying the MOPR to all of PJM and not just certain zones within PJM), the FERC required PJM to retain a key element of its previous MOPR structure, the unit-specific exemption, an element that Exelon had supported removing. Several entities, including two capacity suppliers that Exelon has been working with sought rehearing of that order. | ||||||||||||||||||||||||||||||
In May 2013 (based on the MOPR provisions the FERC approved earlier that month), PJM announced the results of its capacity auction covering the delivery year ending May 31, 2017. Exelon is working with PJM stakeholders on several proposed changes to the PJM tariff aimed at ensuring that capacity resources (including those with state-sanctioned subsidy contracts) cannot inappropriately affect capacity auction prices in PJM. | ||||||||||||||||||||||||||||||
Reliability Pricing Model (Exelon, Generation and BGE). PJM's RPM Base Residual Auctions take place approximately 36 months ahead of the scheduled delivery year. The most recent auction for the delivery year ending May 31, 2017 occurred in May 2013. | ||||||||||||||||||||||||||||||
License Renewals (Exelon and Generation). On June 22, 2011, Generation submitted applications to the NRC to extend the operating licenses of Limerick Units 1 and 2 by 20 years. The current operating licenses for Limerick Units 1 and 2 expire in 2024 and 2029, respectively. In June 2012, the United States Court of Appeals for the DC Circuit vacated the NRC's temporary storage rule on the grounds that the NRC should have conducted a more comprehensive environmental review to support the rule. The temporary storage rule (also referred to as the “waste confidence decision”) recognizes that licensees can safely store spent nuclear fuel at nuclear plants for up to 60 years beyond the original and renewed licensed operating life of the plants and that licensing renewal decisions do not require discussion of the environmental impact of spent fuel stored on site. In August 2012, the NRC placed a hold on issuing new or renewed operating licenses that depend on the temporary storage rule until the court's decision is addressed. In September 2012, the NRC directed NRC Staff to revise the temporary storage rule through rulemaking no later than September 6, 2014. Generation does not expect the NRC to issue license renewals until the end of 2014, at the earliest. | ||||||||||||||||||||||||||||||
On May 29, 2013, Generation submitted applications to the NRC to extend the operating licenses of Byron Units 1 and 2 and Braidwood Units 1 and 2 by 20 years. The current operating licenses for Byron Units 1 and 2 expire in 2024 and 2026, respectively. The current operating licenses for Braidwood Units 1 and 2 expire in 2026 and 2027, respectively. Generation does not expect the NRC to issue license renewals for Byron and Braidwood until 2015 at the earliest. | ||||||||||||||||||||||||||||||
On August 29, 2012 and August 30, 2012, Generation submitted hydroelectric license applications to the FERC for 46-year licenses for the Conowingo Hydroelectric Project (Conowingo) and the Muddy Run Pumped Storage Facility Project (Muddy Run), respectively. Generation is working with stakeholders to resolve licensing issues, including: (1) water quality, (2) fish passage and habitat, and (3) sediment. On August 29, 2013, Exelon filed a water quality certification application pursuant to Section 401 of the Clean Water Act with PA DEP for Muddy Run, addressing these and other issues. The FERC extended the deadline to December 15, 2013 to file a water quality certification application pursuant to Section 401 of the Clean Water Act with the MDE for Conowingo. The stations are being depreciated over their useful lives, which includes the license renewal period. Although Generation expects that these licenses will be renewed, it cannot predict the conditions that may be imposed. Resolution of these issues may require a substantial increase in capital expenditures or may result in increased operating costs and significantly affect Generation's results of operations or financial position. Based on the latest FERC procedural schedule, the FERC licensing process is not expected to be completed prior to the expiration of Muddy Run's current license on August 31, 2014, and the expiration of Conowingo's license on September 1, 2014. However, the stations would continue to operate under annual licenses until FERC takes action on the 46-year license applications. | ||||||||||||||||||||||||||||||
Regulatory Assets and Liabilities (Exelon, ComEd, PECO and BGE) | ||||||||||||||||||||||||||||||
Exelon, ComEd, PECO and BGE each 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 September 30, 2013 and December 31, 2012. For additional information on the specific regulatory assets and liabilities, refer to Note 3 – Regulatory Matters of the Exelon 2012 Form 10-K. | ||||||||||||||||||||||||||||||
30-Sep-13 | Exelon | ComEd | PECO | BGE | ||||||||||||||||||||||||||
Regulatory assets | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | ||||||||||||||||||||||
Pension and other postretirement | ||||||||||||||||||||||||||||||
benefits | $ | 308 | $ | 3,542 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | ||||||||||||||
Deferred income taxes | 12 | 1,424 | 3 | 65 | 0 | 1,296 | 9 | 63 | ||||||||||||||||||||||
AMI programs | 4 | 129 | 4 | 29 | 0 | 48 | 0 | 52 | ||||||||||||||||||||||
AMI meter events | 0 | 5 | 0 | 0 | 0 | 5 | 0 | 0 | ||||||||||||||||||||||
Under-recovered distribution service | ||||||||||||||||||||||||||||||
costs | 129 | 275 | 129 | 275 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||
Debt costs | 12 | 60 | 9 | 56 | 3 | 4 | 1 | 9 | ||||||||||||||||||||||
Fair value of BGE long-term debt (a) | 0 | 225 | 0 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||
Fair value of BGE supply contract (b) | 29 | 3 | 0 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||
Severance | 23 | 13 | 19 | 0 | 0 | 0 | 4 | 13 | ||||||||||||||||||||||
Asset retirement obligations | 0 | 93 | 0 | 68 | 0 | 25 | 0 | 0 | ||||||||||||||||||||||
MGP remediation costs | 47 | 210 | 40 | 175 | 6 | 34 | 1 | 1 | ||||||||||||||||||||||
RTO start-up costs | 2 | 1 | 2 | 1 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||
Under-recovered uncollectible | ||||||||||||||||||||||||||||||
accounts | 0 | 31 | 0 | 31 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||
Renewable energy and associated | ||||||||||||||||||||||||||||||
RECs | 16 | 106 | 16 | 106 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||
Energy and transmission programs | 79 | 0 | 79 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||
Deferred storm costs | 3 | 4 | 0 | 0 | 0 | 0 | 3 | 4 | ||||||||||||||||||||||
Electric generation-related | ||||||||||||||||||||||||||||||
regulatory asset | 13 | 33 | 0 | 0 | 0 | 0 | 13 | 33 | ||||||||||||||||||||||
Rate stabilization deferral | 68 | 175 | 0 | 0 | 0 | 0 | 68 | 175 | ||||||||||||||||||||||
Energy efficiency and demand | ||||||||||||||||||||||||||||||
response programs | 75 | 144 | 0 | 0 | 0 | 0 | 75 | 144 | ||||||||||||||||||||||
Merger integration costs (c) | 1 | 10 | 0 | 0 | 0 | 0 | 1 | 10 | ||||||||||||||||||||||
Under-recovered electric | ||||||||||||||||||||||||||||||
revenue decoupling (f) | 8 | 0 | 0 | 0 | 0 | 0 | 8 | 0 | ||||||||||||||||||||||
Other | 48 | 26 | 34 | 13 | 13 | 7 | 1 | 5 | ||||||||||||||||||||||
Total regulatory assets | $ | 877 | 6,509 | $ | 335 | $ | 819 | $ | 22 | $ | 1,419 | $ | 184 | $ | 509 | |||||||||||||||
30-Sep-13 | Exelon | ComEd | PECO | BGE | ||||||||||||||||||||||||||
Regulatory liabilities | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | ||||||||||||||||||||||
Nuclear decommissioning | $ | 0 | $ | 2,593 | $ | 0 | $ | 2,184 | $ | 0 | $ | 409 | $ | 0 | $ | 0 | ||||||||||||||
Removal costs | 103 | 1,420 | 82 | 1,202 | 0 | 0 | 21 | 218 | ||||||||||||||||||||||
Energy efficiency and demand | ||||||||||||||||||||||||||||||
response programs | 85 | 0 | 49 | 0 | 36 | 0 | 0 | 0 | ||||||||||||||||||||||
DLC Program Costs | 1 | 10 | 0 | 0 | 1 | 10 | 0 | 0 | ||||||||||||||||||||||
Energy efficiency Phase 2 | 0 | 14 | 0 | 0 | 0 | 14 | 0 | 0 | ||||||||||||||||||||||
Electric distribution tax repairs | 20 | 119 | 0 | 0 | 20 | 119 | 0 | 0 | ||||||||||||||||||||||
Gas distribution tax repairs | 8 | 40 | 0 | 0 | 8 | 40 | 0 | 0 | ||||||||||||||||||||||
Energy and transmission programs | 41 | 7 | 0 | 7 | 39 | (d) | 0 | 2 | (h) | 0 | ||||||||||||||||||||
Over-recovered gas and electric | ||||||||||||||||||||||||||||||
universal service fund costs | 7 | 0 | 0 | 0 | 7 | 0 | 0 | 0 | ||||||||||||||||||||||
Revenue subject to refund (e) | 40 | 0 | 40 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||
Over-recovered gas | ||||||||||||||||||||||||||||||
revenue decoupling (f) | 8 | 0 | 0 | 0 | 0 | 0 | 8 | 0 | ||||||||||||||||||||||
Other | 1 | 1 | 0 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||
Total regulatory liabilities | $ | 314 | $ | 4,204 | $ | 171 | $ | 3,393 | $ | 111 | $ | 592 | $ | 31 | $ | 218 | ||||||||||||||
31-Dec-12 | Exelon | ComEd | PECO | BGE | ||||||||||||||||||||||||||
Regulatory assets | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | ||||||||||||||||||||||
Pension and other postretirement | ||||||||||||||||||||||||||||||
benefits | $ | 304 | $ | 3,673 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | ||||||||||||||
Deferred income taxes | 14 | 1,382 | 5 | 62 | 0 | 1,255 | 9 | 65 | ||||||||||||||||||||||
AMI programs | 3 | 70 | 3 | 10 | 0 | 29 | 0 | 31 | ||||||||||||||||||||||
AMI meter events | 0 | 17 | 0 | 0 | 0 | 17 | 0 | 0 | ||||||||||||||||||||||
Under-recovered distribution service | ||||||||||||||||||||||||||||||
costs | 18 | 191 | 18 | 191 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||
Debt costs | 14 | 68 | 11 | 62 | 3 | 6 | 1 | 9 | ||||||||||||||||||||||
Fair value of BGE long-term debt (a) | 0 | 256 | 0 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||
Fair value of BGE supply contract (b) | 77 | 12 | 0 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||
Severance | 29 | 28 | 25 | 12 | 0 | 0 | 4 | 16 | ||||||||||||||||||||||
Asset retirement obligations | 0 | 90 | 0 | 65 | 0 | 25 | 0 | 0 | ||||||||||||||||||||||
MGP remediation costs | 58 | 232 | 51 | 197 | 6 | 33 | 1 | 2 | ||||||||||||||||||||||
RTO start-up costs | 3 | 2 | 3 | 2 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||
Under-recovered electric universal | ||||||||||||||||||||||||||||||
service fund costs | 11 | 0 | 0 | 0 | 11 | 0 | 0 | 0 | ||||||||||||||||||||||
Financial swap with Generation | 0 | 0 | 226 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||
Renewable energy and associated | ||||||||||||||||||||||||||||||
RECs | 18 | 49 | 18 | 49 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||
Energy and transmission programs | 43 | 0 | 14 | 0 | 1 | (g) | 0 | 28 | (h) | 0 | ||||||||||||||||||||
DSP Program costs | 1 | 3 | 0 | 0 | 1 | 3 | 0 | 0 | ||||||||||||||||||||||
DSP II Program costs | 1 | 2 | 0 | 0 | 1 | 2 | 0 | 0 | ||||||||||||||||||||||
Deferred storm costs | 3 | 6 | 0 | 0 | 0 | 0 | 3 | 6 | ||||||||||||||||||||||
Electric generation-related | ||||||||||||||||||||||||||||||
regulatory asset | 16 | 40 | 0 | 0 | 0 | 0 | 16 | 40 | ||||||||||||||||||||||
Rate stabilization deferral | 67 | 225 | 0 | 0 | 0 | 0 | 67 | 225 | ||||||||||||||||||||||
Energy efficiency and demand | ||||||||||||||||||||||||||||||
response programs | 56 | 126 | 0 | 0 | 0 | 0 | 56 | 126 | ||||||||||||||||||||||
Under-recovered electric | ||||||||||||||||||||||||||||||
revenue decoupling (f) | 5 | 0 | 0 | 0 | 0 | 0 | 5 | 0 | ||||||||||||||||||||||
Other | 23 | 25 | 14 | 16 | 9 | 8 | 0 | 2 | ||||||||||||||||||||||
Total regulatory assets | $ | 764 | $ | 6,497 | $ | 388 | $ | 666 | $ | 32 | $ | 1,378 | $ | 190 | $ | 522 | ||||||||||||||
31-Dec-12 | Exelon | ComEd | PECO | BGE | ||||||||||||||||||||||||||
Regulatory liabilities | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | ||||||||||||||||||||||
Nuclear decommissioning | $ | 0 | $ | 2,397 | $ | 0 | $ | 2,037 | $ | 0 | $ | 360 | $ | 0 | $ | 0 | ||||||||||||||
Removal costs | 97 | 1,406 | 75 | 1,192 | 0 | 0 | 22 | 214 | ||||||||||||||||||||||
Energy efficiency and demand | ||||||||||||||||||||||||||||||
response programs | 131 | 0 | 43 | 0 | 88 | 0 | 0 | 0 | ||||||||||||||||||||||
Electric distribution tax repairs | 20 | 132 | 0 | 0 | 20 | 132 | 0 | 0 | ||||||||||||||||||||||
Gas distribution tax repairs | 8 | 46 | 0 | 0 | 8 | 46 | ||||||||||||||||||||||||
Over-recovered uncollectible | ||||||||||||||||||||||||||||||
accounts | 6 | 0 | 6 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||
Energy and transmission programs | 54 | 0 | 6 | 0 | 48 | (d) | 0 | 0 | 0 | |||||||||||||||||||||
Over-recovered gas universal | ||||||||||||||||||||||||||||||
service fund costs | 3 | 0 | 0 | 0 | 3 | 0 | 0 | 0 | ||||||||||||||||||||||
Over-recovered AEPS costs | 2 | 0 | 0 | 0 | 2 | 0 | 0 | 0 | ||||||||||||||||||||||
Revenue subject to refund (e) | 40 | 0 | 40 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||
Over-recovered gas revenue | ||||||||||||||||||||||||||||||
decoupling (f) | 7 | 0 | 0 | 0 | 0 | 0 | 7 | 0 | ||||||||||||||||||||||
Total regulatory liabilities | $ | 368 | $ | 3,981 | $ | 170 | $ | 3,229 | $ | 169 | $ | 538 | $ | 29 | $ | 214 | ||||||||||||||
Represents the regulatory asset recorded at Exelon Corporate for the difference in the fair value of the long-term debt of BGE as of the merger date. The asset is amortized over the life of the underlying debt. See Note 11 – Debt and Credit Agreements for additional information. | ||||||||||||||||||||||||||||||
Represents the regulatory asset recorded at Exelon Corporate representing the fair value of BGE's supply contracts as of the close of the merger date. BGE is allowed full recovery of the costs of its electric and gas supply contracts through approved, regulated rates. The asset is amortized over a period of approximately 3 years. | ||||||||||||||||||||||||||||||
ReIates to integration costs to achieve distribution synergies related to the merger transaction. | ||||||||||||||||||||||||||||||
Includes $18 million related to the DSP program, $13 million related to the over-recovered natural gas costs under the PGC and $8 million related to over-recovered electric transmission costs as of September 30, 2013. As of December 31, 2012, includes $47 million related to the over-recovered electric supply costs under the GSA and $1 million related to the over-recovered natural gas costs under the PGC. | ||||||||||||||||||||||||||||||
Primarily represents the regulatory liability for revenue subject to refund recorded pursuant to the ICC's order in the 2007 Rate Case. See above for discussion regarding the 2007 Rate Case. | ||||||||||||||||||||||||||||||
Represents the electric and gas distribution costs recoverable from or refundable to customers under BGE's decoupling mechanism. | ||||||||||||||||||||||||||||||
Relates to under-recovered transmission costs. | ||||||||||||||||||||||||||||||
Relates to $2 million of over-recovered natural electric supply costs as of September 30, 2013. As of December 31, 2012, includes $9 million of under-recovered electric supply costs and $19 million of under-recovered natural gas supply costs. | ||||||||||||||||||||||||||||||
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 and BGE purchase receivables at a discount to primarily recover uncollectible accounts expense from the suppliers. PECO is required to purchase receivables at face value and permitted to recover uncollectible accounts expense from customers through distribution rates. Exelon, ComEd, PECO and BGE do not record unbilled commodity receivables under the 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 September 30, 2013 and December 31, 2012. | ||||||||||||||||||||||||||||||
As of September 30, 2013 | Exelon | ComEd | PECO | BGE | ||||||||||||||||||||||||||
Purchased receivables (a) | $ | 285 | $ | 124 | $ | 78 | $ | 83 | ||||||||||||||||||||||
Allowance for uncollectible accounts (b) | -31 | -18 | -7 | -6 | ||||||||||||||||||||||||||
Purchased receivables, net | $ | 254 | $ | 106 | $ | 71 | $ | 77 | ||||||||||||||||||||||
As of December 31, 2012 | Exelon | ComEd | PECO | BGE | ||||||||||||||||||||||||||
Purchased receivables (a) | $ | 191 | $ | 55 | $ | 65 | $ | 71 | ||||||||||||||||||||||
Allowance for uncollectible accounts (b) | -21 | -9 | -6 | -6 | ||||||||||||||||||||||||||
Purchased receivables, net | $ | 170 | $ | 46 | $ | 59 | $ | 65 | ||||||||||||||||||||||
__________ | ||||||||||||||||||||||||||||||
(a) PECO's gas POR program became effective on January 1, 2012 and includes a 1% discount on purchased receivables in order to recover the implementation costs of the program. If the costs are not fully recovered when PECO files its next gas distribution rate case, PECO will propose a mechanism to recover the remaining implementation costs as a distribution charge to low volume transportation customers or apply future discounts on purchased receivables from natural gas suppliers serving those customers. | ||||||||||||||||||||||||||||||
(b) For ComEd and BGE, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through its Purchase of Receivables with Consolidated Billing (PORCB) tariff. | ||||||||||||||||||||||||||||||
Commonwealth Edison Co [Member] | ' | |||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ' | |||||||||||||||||||||||||||||
Regulatory Matters (Exelon, Generation, ComEd, PECO and BGE) | ' | |||||||||||||||||||||||||||||
5. Regulatory Matters (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||||||||||||||||
Regulatory and Legislative Proceedings (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||||||||||||||||
Except for the matters noted below, the disclosures set forth in Note 3 – Regulatory Matters of the Exelon 2012 Form 10-K appropriately represent, in all material respects, the current status of regulatory and legislative proceedings of the Registrants. The following is an update to that discussion. | ||||||||||||||||||||||||||||||
Illinois Regulatory Matters | ||||||||||||||||||||||||||||||
Energy Infrastructure Modernization Act (Exelon and ComEd). Since 2011, ComEd's distribution rates are established through a performance-based rate formula, pursuant to EIMA. EIMA also provides a structure for substantial capital investment by utilities over a ten-year period to modernize Illinois' electric utility infrastructure. Participating utilities are required to file an annual update to the performance-based formula rate tariff on or before May 1, with resulting rates effective in January of the following year. This 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 September 30, 2013, and December 31, 2012, ComEd had recorded a net regulatory asset associated with the distribution formula rate of $404 million and $209 million, respectively. | ||||||||||||||||||||||||||||||
During March 2013, the Illinois House and Senate each passed Senate Bill 9 with supermajority votes to clarify the intent of EIMA on three major issues: the use of year-end rather than average rate base and capital structure in the annual reconciliation, the use of ComEd's weighted average cost of capital interest rate to apply to the annual reconciliation and an allowed return on ComEd's pension asset. On May 22, 2013, the Illinois General Assembly overrode the Governor's May 5, 2013 veto of Senate Bill 9, which resulted in the legislation becoming effective immediately. ComEd projects the override of Senate Bill 9 will result in increased operating revenues of approximately $25 million for 2013 and $65 million in 2014. Also, ComEd projects that Senate Bill 9 will accelerate capital expenditures by approximately $40 million and $45 million in 2013 and 2014, respectively. | ||||||||||||||||||||||||||||||
On May 30, 2013, ComEd updated the distribution formula rate structure to reflect the impacts of Senate Bill 9. On June 5, 2013, the ICC approved the May 30 filing implementing ComEd's formula rate structure change as well as the resulting reduction to the current revenue requirement in effect of $14 million, which was reflected in customer rates effective July 1, 2013. | ||||||||||||||||||||||||||||||
On May 31, 2013, ComEd updated its April 29, 2013, distribution formula rate filing to reflect the impacts of Senate Bill 9. The May 31, 2013 filing establishes the revenue requirement used to set the rates that will take effect in January 2014 after the ICC's review and approval, which is due by December 25, 2013. The revenue requirement requested is based on 2012 actual costs and projected 2013 capital additions as well as an annual reconciliation of the revenue requirement in effect in 2012 to the actual costs incurred for that year. ComEd's current request is a total increase to the revenue requirement including the impacts of Senate Bill 9, of $353 million, reflecting an increase of $162 million for the initial revenue requirement for 2013 and an increase of $191 million for the annual reconciliation for 2012. The revenue requirement provides for a weighted average debt and equity return on distribution rate base of 6.94% inclusive of an allowed return on common equity of 8.72%, reflecting the average rate on 30-year treasury notes plus 580 basis points. | ||||||||||||||||||||||||||||||
On September 4, 2013, the Attorney General filed a complaint (the Complaint) with the ICC to change the formula rate structure approved by the ICC on June 5, 2013. In the Complaint, the Attorney General proposed the following three changes to the formula: 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 October 2, 2013, the ICC opened an investigation (the Investigation) in which it undertook to review the three issues raised in the Complaint and determine if ComEd's current formula rate structure complies with Senate Bill 9. On October 31, 2013, the Attorney General asked to voluntarily withdraw the Complaint. ComEd is unable to predict the outcome of the ICC's Investigation; however, if the ICC were to rule against ComEd on these three issues, the impact could be material to ComEd's results of operations, cash flows, and financial position. ComEd expects the Investigation to be resolved in the fourth quarter of 2013. | ||||||||||||||||||||||||||||||
On April 1, 2013, ComEd filed annual progress reports on both its AMI Implementation Plan and Infrastructure Investment Plan as required by EIMA. On April 9, 2013, the ICC initiated an investigation to review ComEd's progress on its AMI Implementation Plan. The ICC did not initiate an investigation on ComEd's Infrastructure Investment Plan. On June 5, 2013, the ICC issued an interim order approving ComEd's accelerated AMI deployment plan consistent with the provisions of Senate Bill 9. In September 2013, ComEd began smart grid deployment with 60,000 meters to be installed by the end of 2013. On June 26, 2013, the ICC issued a final order on the overall progress of ComEd's AMI Implementation Plan with no significant findings. | ||||||||||||||||||||||||||||||
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 (the same position ComEd took in its 2010 electric distribution rate case (2010 Rate Case) discussed below). 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 Rate Case became effective. In August 2011, ComEd filed testimony in the remand proceeding that no refunds should be required. The ICC subsequently initiated a proceeding on remand. On February 23, 2012, the ICC issued an order on remand in the proceeding 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. | ||||||||||||||||||||||||||||||
On October 1, 2013, the Court ruled against ComEd on the accumulated depreciation issue. The Court affirmed that ComEd owes a refund to customers of $37 million. As of September 30, 2013, and December 31, 2012, ComEd was fully reserved for this liability. ComEd will not seek rehearing or appeal on this matter and is working with the ICC on the process and timing for a refund to customers. | ||||||||||||||||||||||||||||||
2010 Illinois Electric Distribution Rate Case (Exelon and ComEd). On June 30, 2010, ComEd filed its 2010 Rate Case requesting ICC approval for an increase of $396 million to its annual delivery services revenue requirement. This request was subsequently reduced to $343 million to account for changes in tax law, corrections, acceptance of limited adjustments proposed by certain parties and the amounts expected to be recovered in the AMI pilot program tariff. The request to increase the annual revenue requirement was to allow ComEd to recover the costs of substantial investments made since its last rate filing in 2007. The requested increase also reflected increased costs, most notably pension and OPEB, since ComEd's rates were last determined. The original requested rate of return on common equity was 11.5%. In addition, ComEd requested future recovery of certain amounts that were previously recorded as expense that would allow ComEd to recognize a one-time benefit of up to $40 million (pre-tax). The requested increase also included $22 million for increased uncollectible accounts expense, which would increase the threshold for determining over/under recoveries under ComEd's uncollectible accounts tariff. | ||||||||||||||||||||||||||||||
On May 24, 2011, the ICC issued an order, which became effective on June 1, 2011. The order approved a $143 million increase to ComEd's annual delivery services revenue requirement and a 10.5% rate of return on common equity. As expected, the ICC followed the Court's ruling in ComEd's 2007 Rate Case on the post-test year accumulated depreciation issue. The order allowed ComEd to establish or reestablish a net amount of approximately $40 million of previously expensed plant balances or new regulatory assets, which was reflected as a reduction in operating and maintenance expense and income tax expense in 2011. The order also affirmed the current regulatory asset for severance costs, which was challenged by an intervener in the 2010 Rate Case. The order was appealed to the Court by several parties on a number of issues. On May 16, 2013, the Court dismissed as moot the appeals of the ICC's order in the 2010 Rate Case as ComEd now recovers distribution costs under EIMA through a pre-established formula rate tariff. See Note 3 of Exelon's 2012 Form 10-K for further details on ComEd's 2007 Rate Case and 2010 Rate Case. | ||||||||||||||||||||||||||||||
Illinois Procurement Proceedings (Exelon and ComEd). ComEd is permitted to recover its electricity procurement costs from retail customers without mark-up. The IPA's 2013 procurement plan, approved by the ICC, provides for curtailment of the existing long-term contracts for renewable energy and RECs in response to the increased number of ComEd's customers purchasing their energy from competitive electric generation suppliers on their own or through municipal aggregation. In March 2013, ICC staff and the IPA approved ComEd's updated load forecast. Purchases under the existing long-term contracts for energy and the associated RECs were reduced on a pro-rata basis under the terms of those contracts for the June 2013 – May 2014 period to keep the purchases under the statutory rate impact cap. The curtailment's impact on ComEd's financial position and cash flows was immaterial. | ||||||||||||||||||||||||||||||
On December 19, 2012, the ICC issued an order directing ComEd and Ameren (the Utilities) to enter into 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 proposed term of the sourcing agreement is 20 years. The project was approved by the DOE on February 4, 2013. The sourcing agreement was approved by the ICC on June 26, 2013 in a separate proceeding, with the ICC ordering ComEd to execute the sourcing agreement no later than 60 days after the date of the order. The sourcing agreement stipulates that the Utilities will pay FutureGen's contract prices, which are set annually based on a formula rate construct. The contract prices are based on the difference between the costs of the facility and the revenues FutureGen receives from selling capacity and energy from the unit into the MISO or other markets, as well as any other revenue FutureGen receives from the operation of the facility. The order also directs the Utilities to recover (or pass along) these costs from the Utilities' distribution system customers, regardless of whether they purchase electricity from the utility or from competitive electric generation suppliers. On January 22, 2013, ComEd filed an application for rehearing, requesting the ICC reconsider its December 2012 order requiring the Utilities to procure the entire output of the FutureGen facility. On January 29, 2013, the ICC denied ComEd's rehearing request. ComEd filed an appeal with the Illinois Appellate Court on February 22, 2013, questioning the legality of requiring ComEd to procure power for retail customers purchasing electricity from competitive electric generation suppliers. | ||||||||||||||||||||||||||||||
On August 22, 2013, the Utilities executed the contract with FutureGen in accordance with the ICC order. However, in the event the order is reversed as a result of the appeal, ComEd's obligations under the contract should be suspended. Depending on the ultimate outcome of the appeals, the eventual market conditions and the cost of the facility, the sourcing agreement could have a material adverse impact on Exelon's and ComEd's cash flows and financial positions. | ||||||||||||||||||||||||||||||
See Note 18 – Commitments and Contingencies for additional information on ComEd's energy commitments and ICC's proceedings related to storm waivers. | ||||||||||||||||||||||||||||||
[1] | Primarily represents the regulatory liability for revenue subject to refund recorded pursuant to the ICCbs order in the 2007 Rate Case. See above for discussion regarding the 2007 Rate Case. |
Investment_in_Constellation_En
Investment in Constellation Energy Nuclear Group, LLC (Exelon and Generation) | 9 Months Ended | |||||||||||
Sep. 30, 2013 | ||||||||||||
Equity Method Investments and Joint Ventures [Line Items] | ' | |||||||||||
Investment in Constellation Energy Nuclear Group, LLC (Exelon and Generation) | ' | |||||||||||
6. Investment in Constellation Energy Nuclear Group, LLC (Exelon and Generation) | ||||||||||||
As a result of the Constellation merger, Generation owns a 50.01% interest in CENG, a nuclear generation business. Generation's total equity in earnings (losses) on the investment in CENG is as follows: | ||||||||||||
Three Months | Three Months | |||||||||||
Ended September 30, | Ended September 30, | |||||||||||
2013 | 2012 | |||||||||||
Equity investment income | $ | 68 | $ | 58 | ||||||||
Amortization of basis difference in CENG | -31 | -57 | ||||||||||
Total equity in earnings - CENG | $ | 37 | $ | 1 | ||||||||
Nine Months | For the Period March 12, | |||||||||||
Ended September 30, | through September 30, | |||||||||||
2013 | 2012 | |||||||||||
Equity investment income (loss) | $ | 93 | $ | 53 | ||||||||
Amortization of basis difference in CENG | -88 | -131 | ||||||||||
Total equity in earnings (losses) - CENG | $ | 5 | $ | -78 | ||||||||
As of March 12, 2012, Generation had an initial basis difference of approximately $204 million between the initial carrying value of its investment in CENG and its underlying equity in CENG. This basis difference resulted from the requirement to record the investment in CENG at fair value under purchase accounting while the underlying assets and liabilities within CENG continue to be accounted for on a historical cost basis. Generation is amortizing this basis difference over the respective useful lives of the assets and liabilities of CENG or as those assets and liabilities affect the earnings of CENG. | ||||||||||||
Based on tax sharing provisions contained in the operating agreement for CENG, Generation may be eligible for distributions from its investment in CENG in excess of its 50.01% ownership interest. Through purchase accounting, Generation has recorded the fair value of expected future distributions. When these distributions are realized, Generation will record a reduction in its investment in CENG. Any distributions in excess of Generation's investment in CENG would be recorded in earnings. | ||||||||||||
Related Party Transactions (Exelon and Generation) | ||||||||||||
CENG | ||||||||||||
Generation has an agreement under which it is purchasing 85% of the output of CENG's nuclear plants that is not sold to third parties under pre-existing firm and unit contingent PPAs through 2014. Beginning on January 1, 2015 and continuing to the end of the life of the respective plants, Generation will purchase on a unit contingent basis 50.01% of the output of CENG's nuclear plants, and EDF will purchase on a unit contingent basis 49.99% of the output. | ||||||||||||
In addition to the PPA, Generation has a power services agency agreement (PSAA) with the CENG plants, which expires on December 31, 2014. The PSAA is a five-year agreement under which Generation provides scheduling, asset management and billing services to the CENG plants for a specified monthly fee. The charges for services reflect the cost of the services. | ||||||||||||
In addition to the PSAA, Exelon has a shared services agreement (SSA) with CENG, which expires in 2017. Pursuant to an agreement between Exelon and EDF, the pricing in the SSA for services reflect actual costs determined on the same basis that BSC charges its affiliates for similar services subject to an annual cap for most SSA services provided. | ||||||||||||
The affect of transactions under these agreements on Exelon's and Generation's Consolidated Financial Statements is summarized below: | ||||||||||||
Income/(Expense) | Income/(Expense) | Accounts | ||||||||||
Three Months | Nine Months | Income | Receivable/ | |||||||||
Ended | Ended | Statement | (Accounts Payable) | |||||||||
Agreement | 30-Sep-13 | 30-Sep-13 | Classification | At September 30, 2013 | ||||||||
PPA | $ | -269 | $ | -748 | Purchased power and fuel | $ | -76 | |||||
PSAA | 1 | 3 | Operating revenues | - | ||||||||
SSA | 10 | 32 | Operating revenues | 4 | ||||||||
Income/(Expense) | Income/(Expense) | Accounts | ||||||||||
Three Months | For the Period | Income | Receivable/ | |||||||||
Ended | March 12 through | Statement | (Accounts Payable) | |||||||||
Agreement | 30-Sep-12 | 30-Sep-12 | Classification | At September 30, 2012 | ||||||||
PPA | $ | -282 | $ | -541 | Purchased power and fuel | $ | -86 | |||||
PSAA | 1 | 2 | Operating revenues | - | ||||||||
SSA | 14 | 30 | Operating revenues | 5 | ||||||||
The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions. | ||||||||||||
Exelon Generation Co L L C [Member] | ' | |||||||||||
Equity Method Investments and Joint Ventures [Line Items] | ' | |||||||||||
Investment in Constellation Energy Nuclear Group, LLC (Exelon and Generation) | ' | |||||||||||
6. Investment in Constellation Energy Nuclear Group, LLC (Exelon and Generation) | ||||||||||||
As a result of the Constellation merger, Generation owns a 50.01% interest in CENG, a nuclear generation business. Generation's total equity in earnings (losses) on the investment in CENG is as follows: | ||||||||||||
Three Months | Three Months | |||||||||||
Ended September 30, | Ended September 30, | |||||||||||
2013 | 2012 | |||||||||||
Equity investment income | $ | 68 | $ | 58 | ||||||||
Amortization of basis difference in CENG | -31 | -57 | ||||||||||
Total equity in earnings - CENG | $ | 37 | $ | 1 | ||||||||
Nine Months | For the Period March 12, | |||||||||||
Ended September 30, | through September 30, | |||||||||||
2013 | 2012 | |||||||||||
Equity investment income (loss) | $ | 93 | $ | 53 | ||||||||
Amortization of basis difference in CENG | -88 | -131 | ||||||||||
Total equity in earnings (losses) - CENG | $ | 5 | $ | -78 | ||||||||
As of March 12, 2012, Generation had an initial basis difference of approximately $204 million between the initial carrying value of its investment in CENG and its underlying equity in CENG. This basis difference resulted from the requirement to record the investment in CENG at fair value under purchase accounting while the underlying assets and liabilities within CENG continue to be accounted for on a historical cost basis. Generation is amortizing this basis difference over the respective useful lives of the assets and liabilities of CENG or as those assets and liabilities affect the earnings of CENG. | ||||||||||||
Based on tax sharing provisions contained in the operating agreement for CENG, Generation may be eligible for distributions from its investment in CENG in excess of its 50.01% ownership interest. Through purchase accounting, Generation has recorded the fair value of expected future distributions. When these distributions are realized, Generation will record a reduction in its investment in CENG. Any distributions in excess of Generation's investment in CENG would be recorded in earnings. | ||||||||||||
Related Party Transactions (Exelon and Generation) | ||||||||||||
CENG | ||||||||||||
Generation has an agreement under which it is purchasing 85% of the output of CENG's nuclear plants that is not sold to third parties under pre-existing firm and unit contingent PPAs through 2014. Beginning on January 1, 2015 and continuing to the end of the life of the respective plants, Generation will purchase on a unit contingent basis 50.01% of the output of CENG's nuclear plants, and EDF will purchase on a unit contingent basis 49.99% of the output. | ||||||||||||
In addition to the PPA, Generation has a power services agency agreement (PSAA) with the CENG plants, which expires on December 31, 2014. The PSAA is a five-year agreement under which Generation provides scheduling, asset management and billing services to the CENG plants for a specified monthly fee. The charges for services reflect the cost of the services. | ||||||||||||
In addition to the PSAA, Exelon has a shared services agreement (SSA) with CENG, which expires in 2017. Pursuant to an agreement between Exelon and EDF, the pricing in the SSA for services reflect actual costs determined on the same basis that BSC charges its affiliates for similar services subject to an annual cap for most SSA services provided. | ||||||||||||
The affect of transactions under these agreements on Exelon's and Generation's Consolidated Financial Statements is summarized below: | ||||||||||||
Income/(Expense) | Income/(Expense) | Accounts | ||||||||||
Three Months | Nine Months | Income | Receivable/ | |||||||||
Ended | Ended | Statement | (Accounts Payable) | |||||||||
Agreement | 30-Sep-13 | 30-Sep-13 | Classification | At September 30, 2013 | ||||||||
PPA | $ | -269 | $ | -748 | Purchased power and fuel | $ | -76 | |||||
PSAA | 1 | 3 | Operating revenues | - | ||||||||
SSA | 10 | 32 | Operating revenues | 4 | ||||||||
Income/(Expense) | Income/(Expense) | Accounts | ||||||||||
Three Months | For the Period | Income | Receivable/ | |||||||||
Ended | March 12 through | Statement | (Accounts Payable) | |||||||||
Agreement | 30-Sep-12 | 30-Sep-12 | Classification | At September 30, 2012 | ||||||||
PPA | $ | -282 | $ | -541 | Purchased power and fuel | $ | -86 | |||||
PSAA | 1 | 2 | Operating revenues | - | ||||||||
SSA | 14 | 30 | Operating revenues | 5 | ||||||||
On July 29, 2013, Exelon, Generation and subsidiaries of Generation entered into a Master Agreement with EDF, EDF Inc. (EDFI) (a subsidiary of EDF) and CENG. The Master Agreement contemplates that the parties will execute a series of additional agreements at a closing that will occur following the receipt of regulatory approvals and the satisfaction of other customary closing conditions. Exelon currently expects that the closing will occur late in the first quarter or early in the second quarter of 2014. | ||||||||||||
At the closing, Generation, CENG and subsidiaries of CENG will execute a Nuclear Operating Services Agreement pursuant to which Generation will operate the CENG nuclear generation fleet owned by CENG subsidiaries and provide corporate and administrative services for the remaining life of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to EDFI's rights as a member of CENG. CENG will reimburse Generation for its direct and allocated costs for such services. The Nuclear Operating Services Agreement will replace the SSA. In addition, at the closing the PSAA will be amended and extended until the complete and permanent cessation of operation of the CENG generation plants. | ||||||||||||
At closing, Generation will make a $400 million loan to CENG bearing interest at 5.25% per annum, payable out of specified available cash flows of CENG. Immediately following receipt of the proceeds of such loan, CENG will make a $400 million special distribution to EDFI. The parties will also execute a Fourth Amended and Restated Operating Agreement for CENG, pursuant to which, among other things, CENG will commit to make preferred distributions to Generation (after repayment of the $400 million loan) quarterly out of specified available cash flows, until Generation has received aggregate distributions of $400 million plus a return of 8.5% per annum from the date of the special distribution to EDFI. | ||||||||||||
Generation and EDFI will also enter into a Put Option Agreement at closing pursuant to which EDFI will have the option, exercisable beginning in 2016 and thereafter until June 30, 2022, to sell its 49.99% interest in CENG to Generation for a fair market value price determined by agreement of the parties, or absent agreement, a third party arbitration process. The appraisers determining fair market value of EDF's 49.99% interest in CENG under the Put Option Agreement are instructed to take into account all rights and obligations under the CENG Operating Agreement, including Generation's rights with respect to any unpaid aggregate preferred distributions and the related return, and the value of Generation's rights to other distributions. The beginning of the exercise period will be accelerated if Exelon's affiliates cease to own a majority of CENG and exercise a related right to terminate the Nuclear Operating Services Agreement. In addition, under limited circumstances, the period for exercise of the put option may be extended for 18 months. | ||||||||||||
Generation will execute an Indemnity Agreement pursuant to which Generation will indemnify EDF and its affiliates against third party claims that may arise from any future nuclear incident (as defined in the Price Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon will guarantee Generation's obligations under this indemnity. | ||||||||||||
Currently, Exelon and Generation account for its investment in CENG under the equity method of accounting. The transfer of the operating licenses and corresponding operational control to Exelon and Generation will result in Exelon and Generation being required to consolidate the financial position and results of operations of CENG. When that accounting change occurs, Exelon and Generation will derecognize its equity method investment in CENG and will record all assets, liabilities and the non-controlling interest in CENG at fair value on Exelon and Generation's balance sheets. Any difference between the former carrying value and newly recorded fair value at that date will be recognized as a gain or loss upon consolidation, which could be material to Exelon's and Generation's results of operations. |
Impairment_of_Longlived_Assets
Impairment of Long-lived Assets (Exelon and Generation) | 9 Months Ended | |||||
Sep. 30, 2013 | ||||||
Impaired Long-Lived Assets Held and Used [Line Items] | ' | |||||
Impairment Of Long Lived Assets Held [Text Block] | ' | |||||
7. Impairment of Long-Lived Assets (Exelon and Generation) | ||||||
Long-Lived Assets (Exelon and Generation) | ||||||
Generation evaluates long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. In the third quarter of 2013, lower projected wind production and a decline in power prices suggested that the carrying value of certain wind projects may be impaired. Generation concluded that the estimated undiscounted future cash flows and fair value of eleven wind projects, primarily located in West Texas and Minnesota, were less than their respective carrying values at September 30, 2013. The fair value analysis was primarily based on the income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. As a result, long-lived assets held and used with a carrying amount of approximately $75 million were written down to their fair value of $32 million and a pre-tax impairment charge of $39 million, net of the impairment amount attributable to non-controlling interests for certain of the projects, was recorded during the third quarter in operating and maintenance expense in Exelon's and Generation's Consolidated Statements of Operations. | ||||||
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 has been adjusted in both the first and second quarters of 2013 to cancel certain projects. During the first quarter of 2013, 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. For these cancelled projects, Generation recorded approximately $21 million of operating and maintenance expense during the first quarter of 2013 to accrue remaining costs and reverse previously capitalized costs. During the second quarter of 2013, market conditions prompted Generation to cancel the previously deferred extended power uprate projects at the LaSalle and Limerick nuclear stations. For these cancelled projects, Generation recorded a pre-tax charge during the second quarter of 2013 to operating and maintenance expense and interest expense of approximately $92 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 12 – Income Taxes for further information. For financial accounting purposes, the investments are accounted for as direct financing lease investments. UII holds the leasehold interests in the generating stations in several separate bankruptcy remote, special purpose companies it directly or indirectly wholly owns. The lease agreements provide the lessees with fixed purchase options at the end of the lease terms. If the lessees do not exercise the fixed purchase options, Exelon has the ability to require the lessees to return the leasehold interests or to arrange for a third party to bid on a service contract for a period following the lease term. If Exelon chooses the service contract option, the leasehold interests will be returned to Exelon at the end of the term of the service contract. In any event, Exelon will be subject to residual value risk if the lessees do not exercise the fixed purchase options. This risk is partially mitigated by the fair value of the scheduled payments under the service contract. However, such payments are not guaranteed. Further, the term of the service contract is less than the expected remaining useful life of the plants and, therefore, Exelon's exposure to residual value risk will not be mitigated by payments under the service contract in this remaining period. In the fourth quarter of 2000, under the terms of the lease agreements, UII received a prepayment of $1.2 billion for all rent, which reduced the investment in the leases. There are no minimum scheduled lease payments to be received over the remaining term of the leases. | ||||||
Pursuant to the applicable accounting guidance, Exelon is required to review the estimated residual values of its direct financing lease investments at least annually and record an impairment charge if the review indicates an other than temporary decline in the fair value of the residual values below their carrying value. Exelon estimates the fair value of the residual value of its direct financing lease investments under the income approach, which uses a discounted cash flow analysis, which takes into consideration the expected revenues to be generated and costs to be incurred to operate the plants over their remaining useful lives subsequent to the lease end dates. Significant assumptions used in estimating the fair value include fundamental energy and capacity prices, fixed and variable costs, capital expenditure requirements, discount rates, tax rates, and the estimated remaining useful lives of the plants. The estimated fair values also reflect the cash flows associated with the service contract option discussed above given that a market participant would take into consideration all of the terms and conditions contained in the lease agreements. | ||||||
Based on the review performed in the second quarter of 2013, the estimated residual value of one of Exelon's direct financing leases experienced an other than temporary decline given reduced long-term energy and capacity price expectations. As a result, Exelon recorded a $14 million pre-tax impairment charge in the second quarter of 2013, which was recorded in investments and operating and maintenance in the Consolidated Balance Sheet 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. | ||||||
As of December 31, 2012, Exelon concluded that the estimated fair values of the residual values at the end of the lease terms exceeded the residual values established at the lease dates. | ||||||
At September 30, 2013 and December 31, 2012, the components of the net investment in long-term leases were as follows: | ||||||
30-Sep-13 | 31-Dec-12 | |||||
Estimated residual value of leased assets | $ | 1,465 | $ | 1,492 | ||
Less: unearned income | 774 | 807 | ||||
Net investment in long-term leases | $ | 691 | $ | 685 | ||
Exelon Generation Co L L C [Member] | ' | |||||
Impaired Long-Lived Assets Held and Used [Line Items] | ' | |||||
Impairment Of Long Lived Assets Held [Text Block] | ' | |||||
7. Impairment of Long-Lived Assets (Exelon and Generation) | ||||||
Long-Lived Assets (Exelon and Generation) | ||||||
Generation evaluates long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. In the third quarter of 2013, lower projected wind production and a decline in power prices suggested that the carrying value of certain wind projects may be impaired. Generation concluded that the estimated undiscounted future cash flows and fair value of eleven wind projects, primarily located in West Texas and Minnesota, were less than their respective carrying values at September 30, 2013. The fair value analysis was primarily based on the income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. As a result, long-lived assets held and used with a carrying amount of approximately $75 million were written down to their fair value of $32 million and a pre-tax impairment charge of $39 million, net of the impairment amount attributable to non-controlling interests for certain of the projects, was recorded during the third quarter in operating and maintenance expense in Exelon's and Generation's Consolidated Statements of Operations. | ||||||
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 has been adjusted in both the first and second quarters of 2013 to cancel certain projects. During the first quarter of 2013, 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. For these cancelled projects, Generation recorded approximately $21 million of operating and maintenance expense during the first quarter of 2013 to accrue remaining costs and reverse previously capitalized costs. During the second quarter of 2013, market conditions prompted Generation to cancel the previously deferred extended power uprate projects at the LaSalle and Limerick nuclear stations. For these cancelled projects, Generation recorded a pre-tax charge during the second quarter of 2013 to operating and maintenance expense and interest expense of approximately $92 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 12 – Income Taxes for further information. For financial accounting purposes, the investments are accounted for as direct financing lease investments. UII holds the leasehold interests in the generating stations in several separate bankruptcy remote, special purpose companies it directly or indirectly wholly owns. The lease agreements provide the lessees with fixed purchase options at the end of the lease terms. If the lessees do not exercise the fixed purchase options, Exelon has the ability to require the lessees to return the leasehold interests or to arrange for a third party to bid on a service contract for a period following the lease term. If Exelon chooses the service contract option, the leasehold interests will be returned to Exelon at the end of the term of the service contract. In any event, Exelon will be subject to residual value risk if the lessees do not exercise the fixed purchase options. This risk is partially mitigated by the fair value of the scheduled payments under the service contract. However, such payments are not guaranteed. Further, the term of the service contract is less than the expected remaining useful life of the plants and, therefore, Exelon's exposure to residual value risk will not be mitigated by payments under the service contract in this remaining period. In the fourth quarter of 2000, under the terms of the lease agreements, UII received a prepayment of $1.2 billion for all rent, which reduced the investment in the leases. There are no minimum scheduled lease payments to be received over the remaining term of the leases. | ||||||
Pursuant to the applicable accounting guidance, Exelon is required to review the estimated residual values of its direct financing lease investments at least annually and record an impairment charge if the review indicates an other than temporary decline in the fair value of the residual values below their carrying value. Exelon estimates the fair value of the residual value of its direct financing lease investments under the income approach, which uses a discounted cash flow analysis, which takes into consideration the expected revenues to be generated and costs to be incurred to operate the plants over their remaining useful lives subsequent to the lease end dates. Significant assumptions used in estimating the fair value include fundamental energy and capacity prices, fixed and variable costs, capital expenditure requirements, discount rates, tax rates, and the estimated remaining useful lives of the plants. The estimated fair values also reflect the cash flows associated with the service contract option discussed above given that a market participant would take into consideration all of the terms and conditions contained in the lease agreements. | ||||||
Based on the review performed in the second quarter of 2013, the estimated residual value of one of Exelon's direct financing leases experienced an other than temporary decline given reduced long-term energy and capacity price expectations. As a result, Exelon recorded a $14 million pre-tax impairment charge in the second quarter of 2013, which was recorded in investments and operating and maintenance in the Consolidated Balance Sheet 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. | ||||||
As of December 31, 2012, Exelon concluded that the estimated fair values of the residual values at the end of the lease terms exceeded the residual values established at the lease dates. | ||||||
At September 30, 2013 and December 31, 2012, the components of the net investment in long-term leases were as follows: | ||||||
Goodwill_Exelon_Generation_Com
Goodwill (Exelon, Generation, ComEd, PECO and BGE) | 9 Months Ended |
Sep. 30, 2013 | |
Intangible Assets [Line Items] | ' |
Intangible Assets (Exelon, Generation, ComEd, PECO and BGE) | ' |
8. Goodwill (Exelon and ComEd) | |
Goodwill | |
Under the authoritative guidance for the accounting for goodwill, ComEd is required to perform an assessment for possible impairment of its goodwill at least annually or more frequently if an event occurs that would more likely than not reduce the fair value of the ComEd reporting unit below its carrying amount. 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. Consistent with prior impairment tests, the estimated fair value of ComEd was determined using 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 management's best estimate of projected cash flows for ComEd's business. The discounted cash flow analysis used in the interim goodwill impairment assessment 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 the interim assessment indicated no 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 the early termination of EIMA or changes in significant assumptions, including the 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 interim goodwill test, the estimated fair value of ComEd would have needed to decrease by more than 10 percent for ComEd to fail the first step of the impairment test. | |
ComEd's 2013 annual goodwill impairment test is being performed as of November 1, 2013. | |
Commonwealth Edison Co [Member] | ' |
Intangible Assets [Line Items] | ' |
Intangible Assets (Exelon, Generation, ComEd, PECO and BGE) | ' |
8. Goodwill (Exelon and ComEd) | |
Goodwill | |
Under the authoritative guidance for the accounting for goodwill, ComEd is required to perform an assessment for possible impairment of its goodwill at least annually or more frequently if an event occurs that would more likely than not reduce the fair value of the ComEd reporting unit below its carrying amount. 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. Consistent with prior impairment tests, the estimated fair value of ComEd was determined using 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 management's best estimate of projected cash flows for ComEd's business. The discounted cash flow analysis used in the interim goodwill impairment assessment 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 the interim assessment indicated no 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 the early termination of EIMA or changes in significant assumptions, including the 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 interim goodwill test, the estimated fair value of ComEd would have needed to decrease by more than 10 percent for ComEd to fail the first step of the impairment test. | |
ComEd's 2013 annual goodwill impairment test is being performed as of November 1, 2013. | |
Fair_Value_of_Financial_Assets
Fair Value of Financial Assets and Liabilities (Exelon, Generation, ComEd, PECO and BGE) | 9 Months Ended | ||||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||||
Fair Value of Financial Assets and Liabilities [Line Items] | ' | ||||||||||||||||||
Fair Value of Financial Assets and Liabilities (Exelon, Generation, ComEd, PECO and BGE) | ' | ||||||||||||||||||
9. 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, trust preferred securities (long-term debt to financing trusts or junior subordinated debentures), and preferred securities as of September 30, 2013 and December 31, 2012: | |||||||||||||||||||
Exelon | |||||||||||||||||||
30-Sep-13 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Short-term liabilities | $ | 217 | $ | 3 | $ | 214 | $ | 0 | $ | 217 | |||||||||
Long-term debt (including amounts due within one year) | 19,565 | 0 | 19,203 | 1,065 | 20,268 | ||||||||||||||
Long-term debt to financing trusts | 648 | 0 | 0 | 631 | 631 | ||||||||||||||
SNF obligation | 1,021 | 0 | 782 | 0 | 782 | ||||||||||||||
31-Dec-12 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Short-term liabilities | $ | 214 | $ | 4 | $ | 210 | $ | 0 | $ | 214 | |||||||||
Long-term debt (including amounts due within one year) | 18,745 | 0 | 20,244 | 276 | 20,520 | ||||||||||||||
Long-term debt to financing trusts | 648 | 0 | 0 | 664 | 664 | ||||||||||||||
SNF obligation | 1,020 | 0 | 763 | 0 | 763 | ||||||||||||||
Preferred securities of subsidiary | 87 | 0 | 82 | 0 | 82 | ||||||||||||||
Generation | |||||||||||||||||||
30-Sep-13 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Short-term liabilities | $ | 21 | $ | 0 | $ | 21 | $ | 0 | $ | 21 | |||||||||
Long-term debt (including amounts due within one year) | 7,809 | 0 | 6,744 | 1,047 | 7,791 | ||||||||||||||
SNF obligation | 1,021 | 0 | 782 | 0 | 782 | ||||||||||||||
31-Dec-12 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Long-term debt (including amounts due within one year) | $ | 7,483 | $ | 0 | $ | 7,591 | $ | 258 | $ | 7,849 | |||||||||
SNF obligation | 1,020 | 0 | 763 | 0 | 763 | ||||||||||||||
ComEd | |||||||||||||||||||
30-Sep-13 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Short-term liabilities | $ | 153 | $ | 0 | $ | 153 | $ | 0 | $ | 153 | |||||||||
Long-term debt (including amounts due within one year) | 5,674 | 0 | 6,240 | 17 | 6,257 | ||||||||||||||
Long-term debt to financing trust | 206 | 0 | 0 | 195 | 195 | ||||||||||||||
31-Dec-12 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Long-term debt (including amounts due within one year) | $ | 5,567 | $ | 0 | $ | 6,530 | $ | 18 | $ | 6,548 | |||||||||
Long-term debt to financing trust | 206 | 0 | 0 | 212 | 212 | ||||||||||||||
PECO | |||||||||||||||||||
30-Sep-13 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Long-term debt (including amounts due within one year) | $ | 2,496 | $ | 0 | $ | 2,678 | $ | 0 | $ | 2,678 | |||||||||
Long-term debt to financing trusts | 184 | 0 | 0 | 182 | 182 | ||||||||||||||
31-Dec-12 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Short-term liabilities | $ | 210 | $ | 0 | $ | 210 | $ | 0 | $ | 210 | |||||||||
Long-term debt (including amounts due within one year) | 1,947 | 0 | 2,264 | 0 | 2,264 | ||||||||||||||
Long-term debt to financing trusts | 184 | 0 | 0 | 188 | 188 | ||||||||||||||
Preferred securities | 87 | 0 | 82 | 0 | 82 | ||||||||||||||
BGE | |||||||||||||||||||
30-Sep-13 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Short-term liabilities | $ | 43 | $ | 3 | $ | 40 | $ | 0 | $ | 43 | |||||||||
Long-term debt (including amounts due within one year) | 2,045 | 0 | 2,204 | 0 | 2,204 | ||||||||||||||
Long-term debt to financing trusts | 258 | 0 | 0 | 254 | 254 | ||||||||||||||
31-Dec-12 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Long-term debt (including amounts due within one year) | $ | 2,178 | $ | 0 | $ | 2,468 | $ | 0 | $ | 2,468 | |||||||||
Long-term debt to financing trusts | 258 | 0 | 0 | 263 | 263 | ||||||||||||||
Short-Term Liabilities. The short-term liabilities included in the tables above are comprised of short-term borrowings (Level 2), short-term notes payable related to PECO's accounts receivable agreement (Level 2), and dividends payable (included in other current liabilities) (Level 1). The Registrants' carrying amounts of the short-term liabilities are representative of fair value because of the short-term nature of these instruments. See Note 11 - Debt and Credit Agreements for additional information on PECO's accounts receivable agreement. | |||||||||||||||||||
Long-Term Debt. The fair value amounts of Exelon's taxable debt securities (Level 2) are determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to incorporate the credit risk of the Registrants into the discount rates, Exelon obtains pricing (i.e., U.S. Treasury rate plus credit spread) based on trades of existing Exelon debt securities as well as debt securities of other issuers in the electric utility sector with similar credit ratings in both the primary and secondary market, across the Registrants' debt maturity spectrum. The credit spreads of various tenors obtained from this information are added to the appropriate benchmark U.S. Treasury rates in order to determine the current market yields for the various tenors. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note. | |||||||||||||||||||
The fair value of Generation's non-government-backed fixed rate project financing debt (Level 3) is based on market and quoted prices for its own and other project financing debt with similar risk profiles. Given the low trading volume in the project financing debt market, the price quotes used to determine fair value will reflect certain qualitative factors, such as market conditions, investor demand, new developments that might significantly impact the project cash flows or off-taker credit, and other circumstances related to the project (e.g., political and regulatory environment). The fair value of Generation's government-back fixed rate project financing debt (Level 3) is largely based on a discounted cash flow methodology that is similar to the taxable debt securities methodology described above. Due to the lack of market trading data on similar debt, the discount rates are derived based on the original loan interest rate spread to the applicable Treasury rate as well as a current market curve derived from government-backed securities. Variable rate project financing debt resets on a quarterly basis and the carrying value approximates fair value. | |||||||||||||||||||
The Registrants also have tax-exempt debt (Level 3). Due to low trading volume in this market, qualitative factors, such as market conditions, investor demand, and circumstances related to the issuer (i.e., political and regulatory environment), may be incorporated into the credit spreads that are used to obtain the fair value as described above. | |||||||||||||||||||
SNF Obligation. The carrying amount of Generation's SNF obligation (Level 2) is derived from a contract with the DOE to provide for disposal of SNF from Generation's nuclear generating stations. When determining the fair value of the obligation, the future carrying amount of the SNF obligation estimated to be settled in 2025 is calculated by compounding the current book value of the SNF obligation at the 13-week Treasury rate. The compounded obligation amount is discounted back to present value using Generation's discount rate, which is calculated using the same methodology as described above for the taxable debt securities, and an estimated maturity date of 2025. | |||||||||||||||||||
Long-Term Debt to Financing Trusts. Exelon's long-term debt to financing trusts is valued based on publicly traded securities issued by the financing trusts. Due to low trading volume of these securities, qualitative factors, such as market conditions, investor demand, and circumstances related to each issue, this debt is classified as Level 3. | |||||||||||||||||||
Preferred Securities. The fair value of these securities is determined based on the last closing price prior to quarter end, less accrued interest. The securities are registered with the SEC and are public. PECO redeemed all outstanding series of preferred securities on May 1, 2013. See Note 17 - Earnings Per Share and Equity for additional information. | |||||||||||||||||||
Recurring Fair Value Measurements | |||||||||||||||||||
Exelon records the fair value of assets and liabilities in accordance with the hierarchy established by the authoritative guidance for fair value measurements. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows: | |||||||||||||||||||
Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to access as of the reporting date. Financial assets and liabilities utilizing Level 1 inputs include active exchange-traded equity securities and funds, certain exchange-based derivatives, and money market funds. | |||||||||||||||||||
Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data. Financial assets and liabilities utilizing Level 2 inputs include fixed income securities, derivatives, commingled and mutual investment funds priced at NAV per fund share and fair value hedges. | |||||||||||||||||||
Level 3 — unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability. Financial assets and liabilities utilizing Level 3 inputs include infrequently traded securities and derivatives, investments priced using an alternative pricing mechanism, and middle market lending using third party valuations. | |||||||||||||||||||
Exelon | |||||||||||||||||||
The following tables present assets and liabilities measured and recorded at fair value on Exelon's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of September 30, 2013 and December 31, 2012: | |||||||||||||||||||
As of September 30, 2013 | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Assets | |||||||||||||||||||
Cash equivalents(a) | $ | 1 | $ | 0 | $ | 0 | $ | 1 | |||||||||||
Nuclear decommissioning trust fund investments | |||||||||||||||||||
Cash equivalents | 558 | 0 | 0 | 558 | |||||||||||||||
Equity | |||||||||||||||||||
Individually held | 1,600 | 0 | 0 | 1,600 | |||||||||||||||
Exchange traded funds | 110 | 0 | 0 | 110 | |||||||||||||||
Commingled funds | 0 | 2,114 | 0 | 2,114 | |||||||||||||||
Equity funds subtotal | 1,710 | 2,114 | 0 | 3,824 | |||||||||||||||
Fixed income | |||||||||||||||||||
Debt securities issued by the U.S. Treasury and other | |||||||||||||||||||
U.S. government corporations and agencies | 938 | 0 | 0 | 938 | |||||||||||||||
Debt securities issued by states of the United States | |||||||||||||||||||
and political subdivisions of the states | 0 | 295 | 0 | 295 | |||||||||||||||
Debt securities issued by foreign governments | 0 | 84 | 0 | 84 | |||||||||||||||
Corporate debt securities | 0 | 1,712 | 0 | 1,712 | |||||||||||||||
Federal agency mortgage-backed securities | 0 | 16 | 0 | 16 | |||||||||||||||
Commercial mortgage-backed securities (non-agency) | 0 | 41 | 0 | 41 | |||||||||||||||
Residential mortgage-backed securities (non-agency) | 0 | 7 | 0 | 7 | |||||||||||||||
Mutual funds | 0 | 29 | 0 | 29 | |||||||||||||||
Fixed income subtotal | 938 | 2,184 | 0 | 3,122 | |||||||||||||||
Middle market lending | 0 | 0 | 245 | 245 | |||||||||||||||
Other debt obligations | 0 | 14 | 0 | 14 | |||||||||||||||
Nuclear decommissioning trust fund investments subtotal(b) | 3,206 | 4,312 | 245 | 7,763 | |||||||||||||||
Pledged assets for Zion Station decommissioning | |||||||||||||||||||
Cash equivalents | 0 | 25 | 0 | 25 | |||||||||||||||
Equity | |||||||||||||||||||
Individually held | 4 | 0 | 0 | 4 | |||||||||||||||
Equity funds subtotal | 4 | 0 | 0 | 4 | |||||||||||||||
Fixed income | |||||||||||||||||||
Debt securities issued by the U.S. Treasury and other | |||||||||||||||||||
U.S. government corporations and agencies | 89 | 7 | 0 | 96 | |||||||||||||||
Debt securities issued by states of the United States | |||||||||||||||||||
and political subdivisions of the states | 0 | 24 | 0 | 24 | |||||||||||||||
Corporate debt securities | 0 | 217 | 0 | 217 | |||||||||||||||
Federal agency mortgage-backed securities | 0 | 7 | 0 | 7 | |||||||||||||||
Fixed income subtotal | 89 | 255 | 0 | 344 | |||||||||||||||
Middle market lending | 0 | 0 | 106 | 106 | |||||||||||||||
Pledged assets for Zion Station decommissioning subtotal(c) | 93 | 280 | 106 | 479 | |||||||||||||||
Rabbi trust investments | |||||||||||||||||||
Cash equivalents | 2 | 0 | 0 | 2 | |||||||||||||||
Mutual funds(d)(e) | 49 | 0 | 0 | 49 | |||||||||||||||
Rabbi trust investments subtotal | 51 | 0 | 0 | 51 | |||||||||||||||
Commodity derivative assets | |||||||||||||||||||
Economic hedges | 540 | 2,541 | 703 | 3,784 | |||||||||||||||
Proprietary trading | 666 | 1,184 | 174 | 2,024 | |||||||||||||||
Effect of netting and allocation of collateral(f) | -1,251 | -2,785 | -311 | -4,347 | |||||||||||||||
Commodity derivative assets subtotal | -45 | 940 | 566 | 1,461 | |||||||||||||||
Interest rate and foreign currency derivative assets | 34 | 49 | 0 | 83 | |||||||||||||||
Effect of netting and allocation of collateral | -33 | -2 | 0 | -35 | |||||||||||||||
Interest rate and foreign currency derivative assets subtotal | 1 | 47 | 0 | 48 | |||||||||||||||
Other investments | 1 | 0 | 11 | 12 | |||||||||||||||
Total assets | 3,308 | 5,579 | 928 | 9,815 | |||||||||||||||
Liabilities | |||||||||||||||||||
Commodity derivative liabilities | |||||||||||||||||||
Economic hedges | -764 | -1,718 | -363 | -2,845 | |||||||||||||||
Proprietary trading | -686 | -1,135 | -155 | -1,976 | |||||||||||||||
Effect of netting and allocation of collateral(f) | 1,359 | 2,843 | 291 | 4,493 | |||||||||||||||
Commodity derivative liabilities subtotal(h) | -91 | -10 | -227 | -328 | |||||||||||||||
Interest rate and foreign currency derivative liabilities | -34 | -17 | 0 | 0 | -51 | ||||||||||||||
Effect of netting and allocation of collateral | 33 | 2 | 0 | 35 | |||||||||||||||
Interest rate and foreign currency derivative liabilities subtotal | -1 | -15 | 0 | -16 | |||||||||||||||
Deferred compensation obligation | 0 | -108 | 0 | -108 | |||||||||||||||
Total liabilities | -92 | -133 | -227 | -452 | |||||||||||||||
Total net assets | $ | 3,216 | $ | 5,446 | $ | 701 | $ | 9,363 | |||||||||||
As of December 31, 2012 | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Assets | |||||||||||||||||||
Cash equivalents(a) | $ | 995 | $ | 0 | $ | 0 | $ | 995 | |||||||||||
Nuclear decommissioning trust fund investments | |||||||||||||||||||
Cash equivalents | 245 | 0 | 0 | 245 | |||||||||||||||
Equity | |||||||||||||||||||
Individually held | 1,480 | 0 | 0 | 1,480 | |||||||||||||||
Commingled funds | 0 | 1,933 | 0 | 1,933 | |||||||||||||||
Equity funds subtotal | 1,480 | 1,933 | 0 | 3,413 | |||||||||||||||
Fixed income | |||||||||||||||||||
Debt securities issued by the U.S. Treasury and other | |||||||||||||||||||
U.S. government corporations and agencies | 1,057 | 0 | 0 | 1,057 | |||||||||||||||
Debt securities issued by states of the United States | |||||||||||||||||||
and political subdivisions of the states | 0 | 321 | 0 | 321 | |||||||||||||||
Debt securities issued by foreign governments | 0 | 93 | 0 | 93 | |||||||||||||||
Corporate debt securities | 0 | 1,788 | 0 | 1,788 | |||||||||||||||
Federal agency mortgage-backed securities | 0 | 24 | 0 | 24 | |||||||||||||||
Commercial mortgage-backed securities (non-agency) | 0 | 45 | 0 | 45 | |||||||||||||||
Residential mortgage-backed securities (non-agency) | 0 | 11 | 0 | 11 | |||||||||||||||
Mutual funds | 0 | 23 | 0 | 23 | |||||||||||||||
Fixed income subtotal | 1,057 | 2,305 | 0 | 3,362 | |||||||||||||||
Middle market lending | 0 | 0 | 183 | 183 | |||||||||||||||
Other debt obligations | 0 | 15 | 0 | 15 | |||||||||||||||
Nuclear decommissioning trust fund investments subtotal(b) | 2,782 | 4,253 | 183 | 7,218 | |||||||||||||||
Pledged assets for Zion decommissioning | |||||||||||||||||||
Cash equivalents | 0 | 23 | 0 | 23 | |||||||||||||||
Equity | |||||||||||||||||||
Individually held | 14 | 0 | 0 | 14 | |||||||||||||||
Commingled funds | 0 | 9 | 0 | 9 | |||||||||||||||
Equity funds subtotal | 14 | 9 | 0 | 23 | |||||||||||||||
Fixed income | |||||||||||||||||||
Debt securities issued by the U.S. Treasury and other | |||||||||||||||||||
U.S. government corporations and agencies | 118 | 12 | 0 | 130 | |||||||||||||||
Debt securities issued by states of the United States | |||||||||||||||||||
and political subdivisions of the states | 0 | 37 | 0 | 37 | |||||||||||||||
Corporate debt securities | 0 | 249 | 0 | 249 | |||||||||||||||
Federal agency mortgage-backed securities | 0 | 49 | 0 | 49 | |||||||||||||||
Commercial mortgage-backed securities (non-agency) | 0 | 6 | 0 | 6 | |||||||||||||||
Fixed income subtotal | 118 | 353 | 0 | 471 | |||||||||||||||
Middle market lending | 0 | 0 | 89 | 89 | |||||||||||||||
Other debt obligations | 0 | 1 | 0 | 1 | |||||||||||||||
Pledged assets for Zion Station decommissioning subtotal(c) | 132 | 386 | 89 | 607 | |||||||||||||||
Rabbi trust investments | |||||||||||||||||||
Cash equivalents | 2 | 0 | 0 | 2 | |||||||||||||||
Mutual funds(d)(e) | 69 | 0 | 0 | 69 | |||||||||||||||
Rabbi trust investments subtotal | 71 | 0 | 0 | 71 | |||||||||||||||
Commodity derivative assets | |||||||||||||||||||
Economic hedges | 861 | 3,173 | 641 | 4,675 | |||||||||||||||
Proprietary trading | 1,042 | 2,078 | 73 | 3,193 | |||||||||||||||
Effect of netting and allocation of collateral(f) | -1,823 | -4,175 | -58 | -6,056 | |||||||||||||||
Commodity derivative assets subtotal(g) | 80 | 1,076 | 656 | 1,812 | |||||||||||||||
Interest rate and foreign currency derivative assets | 0 | 114 | 0 | 114 | |||||||||||||||
Effect of netting and allocation of collateral | 0 | -51 | 0 | -51 | |||||||||||||||
Interest rate and foreign currency derivative assets subtotal | 0 | 63 | 0 | 63 | |||||||||||||||
Other Investments | 2 | 0 | 17 | 19 | |||||||||||||||
Total assets | 4,062 | 5,778 | 945 | 10,785 | |||||||||||||||
Liabilities | |||||||||||||||||||
Commodity derivative liabilities | |||||||||||||||||||
Economic hedges | -1,041 | -2,289 | -236 | -3,566 | |||||||||||||||
Proprietary trading | -1,084 | -1,959 | -78 | -3,121 | |||||||||||||||
Effect of netting and allocation of collateral(f) | 2,042 | 4,020 | 25 | 6,087 | |||||||||||||||
Commodity derivative liabilities subtotal(g)(h) | -83 | -228 | -289 | -600 | |||||||||||||||
Interest rate and foreign currency derivative liabilities | 0 | -84 | 0 | -84 | |||||||||||||||
Effect of netting and allocation of collateral | 0 | 51 | 0 | 51 | |||||||||||||||
Interest rate and foreign currency derivative liabilities subtotal | 0 | -33 | 0 | -33 | |||||||||||||||
Deferred compensation obligation | 0 | -102 | 0 | -102 | |||||||||||||||
Total liabilities | -83 | -363 | -289 | -735 | |||||||||||||||
Total net assets | $ | 3,979 | $ | 5,415 | $ | 656 | $ | 10,050 | |||||||||||
(a) Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value. | |||||||||||||||||||
(b) Excludes net assets of $13 million and $30 million at September 30, 2013 and December 31, 2012, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases. | |||||||||||||||||||
(c) Excludes net assets of $7 million at both September 30, 2013 and December 31, 2012. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases. | |||||||||||||||||||
(d) The mutual funds held by the Rabbi trusts include $49 million related to deferred compensation at September 30, 2013, and $53 million related to deferred compensation and $16 million related to Supplemental Executive Retirement Plan at December 31, 2012. . | |||||||||||||||||||
(e) Excludes $30 million and $28 million of the cash surrender value of life insurance investments at September 30, 2013 and December 31, 2012, respectively. | |||||||||||||||||||
(f) Includes collateral postings (received) from counterparties. Collateral posted (received) from counterparties, net of collateral paid to counterparties, totaled $108 million, $58 million and $(20) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of September 30, 2013. Collateral posted (received) from counterparties, net of collateral paid to counterparties, totaled $219 million, $(155) million and $(33) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2012. | |||||||||||||||||||
(g) The Level 3 balance does not include current assets for Generation and current liabilities for ComEd of $226 million at December 31, 2012, related to the fair value of Generation's financial swap contract with ComEd. | |||||||||||||||||||
(h) The Level 3 balance includes the current and noncurrent liability of $16 million and $106 million at September 30, 2013, respectively, and $18 million and $49 million at December 31, 2012, respectively, related to floating-to-fixed energy swap contracts with unaffiliated suppliers. | |||||||||||||||||||
The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and nine months ended September 30, 2013 and 2012: | |||||||||||||||||||
Three Months Ended September 30, 2013 | Nuclear Decommissioning Trust Fund Investments | Pledged Assets for Zion Station Decommissioning | Mark-to-Market Derivatives | Other Investments | Total | ||||||||||||||
Balance as of June 30, 2013 | $ | 240 | $ | 111 | $ | 431 | $ | 11 | $ | 793 | |||||||||
Total realized / unrealized losses | |||||||||||||||||||
Included in net income | 0 | 0 | -32 | (a) | 0 | -32 | |||||||||||||
Included in other comprehensive income | 0 | 0 | 0 | 0 | 0 | ||||||||||||||
Included in regulatory assets | -1 | 0 | -37 | 0 | -38 | ||||||||||||||
Included in payable for Zion Station decommissioning | 0 | 0 | 0 | 0 | 0 | ||||||||||||||
Change in collateral | 0 | 0 | -30 | 0 | -30 | ||||||||||||||
Purchases, sales, issuances and settlements | |||||||||||||||||||
Purchases | 23 | 10 | 8 | 0 | 41 | ||||||||||||||
Sales | -14 | -15 | 0 | 0 | -29 | ||||||||||||||
Settlements | -3 | 0 | 0 | 0 | -3 | ||||||||||||||
Transfers into Level 3 | 0 | 0 | 4 | 0 | 4 | ||||||||||||||
Transfers out of Level 3 | 0 | 0 | -5 | 0 | -5 | ||||||||||||||
Balance as of September 30, 2013 | $ | 245 | $ | 106 | $ | 339 | $ | 11 | $ | 701 | |||||||||
The amount of total gains included in income | |||||||||||||||||||
attributed to the change in unrealized gains related to assets and liabilities held for the three months ended September 30, 2013 | $ | 0 | $ | 0 | $ | 51 | $ | 0 | $ | 51 | |||||||||
Nine Months Ended September 30, 2013 | Nuclear Decommissioning Trust Fund Investments | Pledged Assets for Zion Station Decommissioning | Mark-to-Market Derivatives | Other Investments | Total | ||||||||||||||
Balance as of December 31, 2012 | $ | 183 | $ | 89 | $ | 367 | $ | 17 | $ | 656 | |||||||||
Total realized / unrealized gains (losses) | |||||||||||||||||||
Included in net income | 2 | 0 | -1 | (a) | 0 | 1 | |||||||||||||
Included in other comprehensive income | 0 | 0 | 0 | 0 | 0 | ||||||||||||||
Included in regulatory assets | 8 | 0 | -55 | (b) | 0 | -47 | |||||||||||||
Included in payable for Zion Station decommissioning | 0 | 1 | 0 | 0 | 1 | ||||||||||||||
Change in collateral | 0 | 0 | 13 | 0 | 13 | ||||||||||||||
Purchases, sales, issuances and settlements | |||||||||||||||||||
Purchases | 90 | 43 | 16 | 2 | 151 | ||||||||||||||
Sales | -27 | -27 | -8 | -8 | -70 | ||||||||||||||
Settlements | -11 | 0 | 0 | 0 | -11 | ||||||||||||||
Transfers into Level 3 | 0 | 0 | 11 | 0 | 11 | ||||||||||||||
Transfers out of Level 3 | 0 | 0 | -4 | 0 | -4 | ||||||||||||||
Balance as of September 30, 2013 | $ | 245 | $ | 106 | $ | 339 | $ | 11 | $ | 701 | |||||||||
The amount of total gains included in income | |||||||||||||||||||
attributed to the change in unrealized gains related to assets and liabilities held for the nine months ended September 30, 2013 | $ | 1 | $ | 0 | $ | 159 | $ | 0 | $ | 160 | |||||||||
(a) Includes the reclassification of $83 million and $160 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2013. | |||||||||||||||||||
(b) Excludes decreases in fair value of $11 million and realized losses reclassified due to settlements of $215 million associated with Generation's financial swap contract with ComEd for the nine months ended September 30, 2013. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements. | |||||||||||||||||||
Three Months Ended September 30, 2012 | Nuclear Decommissioning Trust Fund Investments | Pledged Assets for Zion Station Decommissioning | Mark-to-Market Derivatives | Other Investments | Total | ||||||||||||||
Balance as of June 30, 2012 | $ | 54 | $ | 59 | $ | 295 | $ | 17 | $ | 425 | |||||||||
Total realized / unrealized gains (losses) | |||||||||||||||||||
Included in net income | 0 | 0 | -97 | (a) | 0 | -97 | |||||||||||||
Included in other comprehensive income | 0 | 0 | 0 | 0 | 0 | ||||||||||||||
Included in regulatory assets | 2 | 0 | 41 | (b) | 0 | 43 | |||||||||||||
Included in payable for Zion Station | |||||||||||||||||||
decommissioning | 0 | 1 | 0 | 0 | 1 | ||||||||||||||
Change in collateral | 0 | 0 | -15 | 0 | -15 | ||||||||||||||
Purchases, sales, issuances and settlements | |||||||||||||||||||
Purchases | 14 | 4 | 0 | 0 | 18 | ||||||||||||||
Sales | 0 | 0 | 0 | 0 | 0 | ||||||||||||||
Transfers into Level 3 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||
Transfers out of Level 3 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||
Balance as of September 30, 2012 | $ | 70 | $ | 64 | $ | 224 | $ | 17 | $ | 375 | |||||||||
The amount of total losses included in income | |||||||||||||||||||
attributed to the change in unrealized losses related to assets and liabilities held for the three months ended September 30, 2012 | $ | 0 | $ | 0 | $ | -42 | $ | 0 | $ | -42 | |||||||||
Nine Months Ended September 30, 2012 | Nuclear Decommissioning Trust Fund Investments | Pledged Assets for Zion Decommissioning | Mark-to-Market Derivatives | Other Investments | Total | ||||||||||||||
Balance as of December 31, 2011 | $ | 13 | $ | 37 | $ | 17 | $ | 0 | $ | 67 | |||||||||
Total realized / unrealized gains (losses) | |||||||||||||||||||
Included in net income | 0 | 0 | -78 | (a) | 0 | -78 | |||||||||||||
Included in other comprehensive income | 0 | 0 | 0 | 0 | 0 | ||||||||||||||
Included in regulatory assets | 2 | 0 | 36 | (b) | 0 | 38 | |||||||||||||
Included in payable for Zion Station | |||||||||||||||||||
decommissioning | 0 | 0 | 0 | 0 | 0 | ||||||||||||||
Change in collateral | 0 | 0 | -7 | 0 | -7 | ||||||||||||||
Purchases, sales, issuances and settlements | |||||||||||||||||||
Purchases | 55 | 36 | 329 | (c) | 17 | 437 | |||||||||||||
Sales | 0 | -9 | 0 | 0 | -9 | ||||||||||||||
Transfers into Level 3 | 0 | 0 | -34 | 0 | -34 | ||||||||||||||
Transfers out of Level 3 | 0 | 0 | -39 | 0 | -39 | ||||||||||||||
Balance as of September 30, 2012 | $ | 70 | $ | 64 | $ | 224 | $ | 17 | $ | 375 | |||||||||
The amount of total gains included in income | |||||||||||||||||||
attributed to the change in unrealized gains related to assets and liabilities held for the nine months ended September 30, 2012 | $ | 0 | $ | 0 | $ | 62 | $ | 0 | $ | 62 | |||||||||
(a) Includes the reclassification of $55 million and $140 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2012, respectively. | |||||||||||||||||||
(b) Excludes $35 million of decreases in fair value and $86 million of increases in fair value and $119 million and $427 million of realized losses due to settlements for the three and nine months ended September 30, 2012 of Generation's financial swap contract with ComEd, which eliminates upon consolidation in Exelon's Consolidated Financial Statements. | |||||||||||||||||||
(c) Includes $310 million of fair value from contracts and $14 million of other investments acquired as a result of the merger. | |||||||||||||||||||
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 three and nine months ended September 30, 2013 and 2012: | |||||||||||||||||||
Operating Revenue | Purchased Power and Fuel | Other, net (a) | |||||||||||||||||
Total gains (losses) included in income for the three months ended | |||||||||||||||||||
30-Sep-13 | $ | -39 | $ | 7 | $ | 0 | |||||||||||||
Total gains (losses) included in income for the nine months ended | |||||||||||||||||||
30-Sep-13 | $ | -61 | $ | 60 | $ | 2 | |||||||||||||
Change in the unrealized gains relating to assets and liabilities | |||||||||||||||||||
held for the three months ended September 30, 2013 | $ | 42 | $ | 9 | $ | 0 | |||||||||||||
Change in the unrealized gains relating to assets and liabilities | |||||||||||||||||||
held for the nine months ended September 30, 2013 | $ | 81 | $ | 78 | $ | 1 | |||||||||||||
Operating Revenue | Purchased Power and Fuel | Other, net | |||||||||||||||||
Total gains (losses) included in income for the three months | |||||||||||||||||||
ended September 30, 2012 | $ | -101 | $ | 4 | $ | 0 | |||||||||||||
Total losses included in income for the nine months ended | |||||||||||||||||||
30-Sep-12 | $ | -78 | $ | 0 | $ | 0 | |||||||||||||
Change in the unrealized gains (losses) relating to assets and | |||||||||||||||||||
liabilities held for the three months ended September 30, 2012 | $ | -43 | $ | 1 | $ | 0 | |||||||||||||
Change in the unrealized gains (losses) relating to assets and | |||||||||||||||||||
liabilities held for the nine months ended September 30, 2012 | $ | 82 | $ | -20 | $ | 0 | |||||||||||||
(a) Other, net activity consists of realized and unrealized gains (losses) included in income for the NDT funds held by Generation. | |||||||||||||||||||
Generation | |||||||||||||||||||
The following tables present assets and liabilities measured and recorded at fair value on Generation's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of September 30, 2013 and December 31, 2012: | |||||||||||||||||||
As of September 30, 2013 | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Assets | |||||||||||||||||||
Cash equivalents | $ | 674 | $ | 0 | $ | 0 | $ | 674 | |||||||||||
Nuclear decommissioning trust fund investments | |||||||||||||||||||
Cash equivalents | 558 | 0 | 0 | 558 | |||||||||||||||
Equity | |||||||||||||||||||
Individually held | 1,600 | 0 | 0 | 1,600 | |||||||||||||||
Exchange traded funds | 110 | 0 | 0 | 110 | |||||||||||||||
Commingled funds | 0 | 2,114 | 0 | 2,114 | |||||||||||||||
Equity funds subtotal | 1,710 | 2,114 | 0 | 3,824 | |||||||||||||||
Fixed income | |||||||||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. | |||||||||||||||||||
government corporations and agencies | 938 | 0 | 0 | 938 | |||||||||||||||
Debt securities issued by states of the United States and | |||||||||||||||||||
political subdivisions of the states | 0 | 295 | 0 | 295 | |||||||||||||||
Debt securities issued by foreign governments | 0 | 84 | 0 | 84 | |||||||||||||||
Corporate debt securities | 0 | 1,712 | 0 | 1,712 | |||||||||||||||
Federal agency mortgage-backed securities | 0 | 16 | 0 | 16 | |||||||||||||||
Commercial mortgage-backed securities (non-agency) | 0 | 41 | 0 | 41 | |||||||||||||||
Residential mortgage-backed securities (non-agency) | 0 | 7 | 0 | 7 | |||||||||||||||
Mutual funds | 0 | 29 | 0 | 29 | |||||||||||||||
Fixed income subtotal | 938 | 2,184 | 0 | 3,122 | |||||||||||||||
Middle market lending | 0 | 0 | 245 | 245 | |||||||||||||||
Other debt obligations | 0 | 14 | 0 | 14 | |||||||||||||||
Nuclear decommissioning trust fund investments subtotal(b) | 3,206 | 4,312 | 245 | 7,763 | |||||||||||||||
Pledged assets for Zion Station decommissioning | |||||||||||||||||||
Cash equivalents | 0 | 25 | 0 | 25 | |||||||||||||||
Equity | |||||||||||||||||||
Individually held | 4 | 0 | 0 | 4 | |||||||||||||||
Equity funds subtotal | 4 | 0 | 0 | 4 | |||||||||||||||
Fixed income | |||||||||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. | |||||||||||||||||||
government corporations and agencies | 89 | 7 | 0 | 96 | |||||||||||||||
Debt securities issued by states of the United States and | |||||||||||||||||||
political subdivisions of the states | 0 | 24 | 0 | 24 | |||||||||||||||
Corporate debt securities | 0 | 217 | 0 | 217 | |||||||||||||||
Federal agency mortgage-backed securities | 0 | 7 | 0 | 7 | |||||||||||||||
Fixed income subtotal | 89 | 255 | 0 | 344 | |||||||||||||||
Middle market lending | 0 | 0 | 106 | 106 | |||||||||||||||
Pledged assets for Zion Station decommissioning subtotal(c) | 93 | 280 | 106 | 479 | |||||||||||||||
Rabbi trust investments | |||||||||||||||||||
Mutual funds(d) | 12 | 0 | 0 | 12 | |||||||||||||||
Rabbi trust investments subtotal | 12 | 0 | 0 | 12 | |||||||||||||||
Commodity derivative assets | |||||||||||||||||||
Economic hedges | 540 | 2,541 | 703 | 3,784 | |||||||||||||||
Proprietary trading | 666 | 1,184 | 174 | 2,024 | |||||||||||||||
Effect of netting and allocation of collateral(e) | -1,251 | -2,785 | -311 | -4,347 | |||||||||||||||
Commodity derivative assets subtotal | -45 | 940 | 566 | 1,461 | |||||||||||||||
Interest rate and foreign currency derivative assets | 34 | 36 | 0 | 70 | |||||||||||||||
Effect of netting and allocation of collateral | -33 | -2 | 0 | -35 | |||||||||||||||
Interest rate and foreign currency derivative assets subtotal | 1 | 34 | 0 | 35 | |||||||||||||||
Other investments | 1 | 0 | 11 | 12 | |||||||||||||||
Total assets | 3,942 | 5,566 | 928 | 10,436 | |||||||||||||||
Liabilities | |||||||||||||||||||
Commodity derivative liabilities | |||||||||||||||||||
Economic hedges | -764 | -1,718 | -241 | -2,723 | |||||||||||||||
Proprietary trading | -686 | -1,135 | -155 | -1,976 | |||||||||||||||
Effect of netting and allocation of collateral(e) | 1,359 | 2,843 | 291 | 4,493 | |||||||||||||||
Commodity derivative liabilities subtotal | -91 | -10 | -105 | -206 | |||||||||||||||
Interest rate and foreign currency derivative liabilities | -34 | -17 | 0 | -51 | |||||||||||||||
Effect of netting and allocation of collateral | 33 | 2 | 0 | 35 | |||||||||||||||
Interest rate and foreign currency derivative liabilities subtotal | -1 | -15 | 0 | -16 | |||||||||||||||
Deferred compensation obligation | 0 | -27 | 0 | -27 | |||||||||||||||
Total liabilities | -92 | -52 | -105 | -249 | |||||||||||||||
Total net assets | $ | 3,850 | $ | 5,514 | $ | 823 | $ | 10,187 | |||||||||||
As of December 31, 2012 | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Assets | |||||||||||||||||||
Cash equivalents(a) | $ | 487 | $ | 0 | $ | 0 | $ | 487 | |||||||||||
Nuclear decommissioning trust fund investments | |||||||||||||||||||
Cash equivalents | 245 | 0 | 0 | 245 | |||||||||||||||
Equity | |||||||||||||||||||
Individually held | 1,480 | 0 | 0 | 1,480 | |||||||||||||||
Commingled funds | 0 | 1,933 | 0 | 1,933 | |||||||||||||||
Equity funds subtotal | 1,480 | 1,933 | 0 | 3,413 | |||||||||||||||
Fixed income | |||||||||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. | |||||||||||||||||||
government corporations and agencies | 1,057 | 0 | 0 | 1,057 | |||||||||||||||
Debt securities issued by states of the United States and | |||||||||||||||||||
political subdivisions of the states | 0 | 321 | 0 | 321 | |||||||||||||||
Debt securities issued by foreign governments | 0 | 93 | 0 | 93 | |||||||||||||||
Corporate debt securities | 0 | 1,788 | 0 | 1,788 | |||||||||||||||
Federal agency mortgage-backed securities | 0 | 24 | 0 | 24 | |||||||||||||||
Commercial mortgage-backed securities (non-agency) | 0 | 45 | 0 | 45 | |||||||||||||||
Residential mortgage-backed securities (non-agency) | 0 | 11 | 0 | 11 | |||||||||||||||
Mutual funds | 0 | 23 | 0 | 23 | |||||||||||||||
Fixed income subtotal | 1,057 | 2,305 | 0 | 3,362 | |||||||||||||||
Middle market lending | 0 | 0 | 183 | 183 | |||||||||||||||
Other debt obligations | 0 | 15 | 0 | 15 | |||||||||||||||
Nuclear decommissioning trust fund investments subtotal(b) | 2,782 | 4,253 | 183 | 7,218 | |||||||||||||||
Pledged assets for Zion Station decommissioning | |||||||||||||||||||
Cash equivalents | 0 | 23 | 0 | 23 | |||||||||||||||
Equity | |||||||||||||||||||
Individually held | 14 | 0 | 0 | 14 | |||||||||||||||
Commingled funds | 0 | 9 | 0 | 9 | |||||||||||||||
Equity funds subtotal | 14 | 9 | 0 | 23 | |||||||||||||||
Fixed income | |||||||||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. | |||||||||||||||||||
government corporations and agencies | 118 | 12 | 0 | 130 | |||||||||||||||
Debt securities issued by states of the United States and | |||||||||||||||||||
political subdivisions of the states | 0 | 37 | 0 | 37 | |||||||||||||||
Corporate debt securities | 0 | 249 | 0 | 249 | |||||||||||||||
Federal agency mortgage-backed securities | 0 | 49 | 0 | 49 | |||||||||||||||
Commercial mortgage-backed securities (non-agency) | 0 | 6 | 0 | 6 | |||||||||||||||
Fixed income subtotal | 118 | 353 | 0 | 471 | |||||||||||||||
Middle market lending | 0 | 0 | 89 | 89 | |||||||||||||||
Other debt obligations | 0 | 1 | 0 | 1 | |||||||||||||||
Pledged assets for Zion Station decommissioning subtotal(c) | 132 | 386 | 89 | 607 | |||||||||||||||
Rabbi trust investments | |||||||||||||||||||
Cash equivalents | 1 | 0 | 0 | 1 | |||||||||||||||
Mutual funds(d) | 13 | 0 | 0 | 13 | |||||||||||||||
Rabbi trust investments subtotal | 14 | 0 | 0 | 14 | |||||||||||||||
Commodity derivative assets | |||||||||||||||||||
Economic hedges | 861 | 3,173 | 867 | 4,901 | |||||||||||||||
Proprietary trading | 1,042 | 2,078 | 73 | 3,193 | |||||||||||||||
Effect of netting and allocation of collateral(e) | -1,823 | -4,175 | -58 | -6,056 | |||||||||||||||
Commodity and foreign currency assets subtotal(f) | 80 | 1,076 | 882 | 2,038 | |||||||||||||||
Interest rate and foreign currency derivative assets | 0 | 101 | 0 | 101 | |||||||||||||||
Effect of netting and allocation of collateral | 0 | -51 | 0 | -51 | |||||||||||||||
Interest rate and foreign currency derivative assets subtotal | 0 | 50 | 0 | 50 | |||||||||||||||
Other investments | 2 | 0 | 17 | 19 | |||||||||||||||
Total assets | 3,497 | 5,765 | 1,171 | 10,433 | |||||||||||||||
Liabilities | |||||||||||||||||||
Commodity derivative liabilities | |||||||||||||||||||
Economic hedges | -1,041 | -2,289 | -169 | -3,499 | |||||||||||||||
Proprietary trading | -1,084 | -1,959 | -78 | -3,121 | |||||||||||||||
Effect of netting and allocation of collateral(e) | 2,042 | 4,020 | 25 | 6,087 | |||||||||||||||
Commodity derivative liabilities subtotal | -83 | -228 | -222 | -533 | |||||||||||||||
Interest rate derivative liabilities | 0 | -84 | 0 | -84 | |||||||||||||||
Effect of netting and allocation of collateral | 0 | 51 | 0 | 51 | |||||||||||||||
Interest rate and foreign currency derivative liabilities | 0 | -33 | 0 | -33 | |||||||||||||||
Deferred compensation obligation | 0 | -28 | 0 | -28 | |||||||||||||||
Total liabilities | -83 | -289 | -222 | -594 | |||||||||||||||
Total net assets | $ | 3,414 | $ | 5,476 | $ | 949 | $ | 9,839 | |||||||||||
(a) Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value. | |||||||||||||||||||
(b) Excludes net assets of $13 million and $30 million at September 30, 2013 and December 31, 2012, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases. | |||||||||||||||||||
(c) Excludes net assets of $7 at both September 30, 2013 December 31, 2012. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases. | |||||||||||||||||||
(d) Excludes $9 million and $8 million of the cash surrender value of life insurance investments at September 30, 2013 and December 31, 2012, respectively. | |||||||||||||||||||
(e) Includes collateral postings (received) from counterparties. Collateral posted (received) from counterparties, net of collateral paid to counterparties, totaled $108 million, $58 million and $(20) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of September 30, 2013. Collateral posted (received) from counterparties, net of collateral paid to counterparties, totaled $219 million, $(155) million and $(33) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2012. | |||||||||||||||||||
The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and nine months ended September 30, 2013 and 2012: | |||||||||||||||||||
Three Months Ended September 30, 2013 | Nuclear Decommissioning Trust Fund Investments | Pledged Assets for Zion Station Decommissioning | Mark-to-Market Derivatives | Other Investments | Total | ||||||||||||||
Balance as of June 30, 2013 | $ | 240 | $ | 111 | $ | 516 | $ | 11 | $ | 878 | |||||||||
Total realized / unrealized gains (losses) | |||||||||||||||||||
Included in net income | 0 | 0 | -32 | (a) | 0 | -32 | |||||||||||||
Included in noncurrent payables to affiliates | -1 | 0 | 0 | 0 | -1 | ||||||||||||||
Change in collateral | 0 | 0 | -30 | 0 | -30 | ||||||||||||||
Purchases, sales, issuances and settlements | |||||||||||||||||||
Purchases | 23 | 10 | 8 | 0 | 41 | ||||||||||||||
Sales | -14 | -15 | 0 | 0 | -29 | ||||||||||||||
Settlements | -3 | 0 | 0 | 0 | -3 | ||||||||||||||
Transfers into Level 3 | 0 | 0 | 4 | 0 | 4 | ||||||||||||||
Transfers out of Level 3 | 0 | 0 | -5 | 0 | -5 | ||||||||||||||
Balance as of September 30, 2013 | $ | 245 | $ | 106 | $ | 461 | $ | 11 | $ | 823 | |||||||||
The amount of total gains included in income | |||||||||||||||||||
attributed to the change in unrealized gains related to assets and liabilities held for the three months ended September 30, 2013 | $ | 0 | $ | 0 | $ | 51 | $ | 0 | $ | 51 | |||||||||
Nine Months Ended September 30, 2013 | Nuclear Decommissioning Trust Fund Investments | Pledged Assets for Zion Station Decommissioning | Mark-to-Market Derivatives | Other Investments | Total | ||||||||||||||
Balance as of December 31, 2012 | $ | 183 | $ | 89 | $ | 660 | $ | 17 | $ | 949 | |||||||||
Total realized / unrealized gains (losses) | |||||||||||||||||||
Included in net income | 2 | 0 | -8 | (a)(b) | 0 | -6 | |||||||||||||
Included in other comprehensive income | 0 | 0 | -219 | (b) | 0 | -219 | |||||||||||||
Included in noncurrent payables to affiliates | 8 | 0 | 0 | 0 | 8 | ||||||||||||||
Included in payable for Zion Station decommissioning | 0 | 1 | 0 | 0 | 1 | ||||||||||||||
Change in collateral | 0 | 13 | 0 | 13 | |||||||||||||||
Purchases, sales, issuances and settlements | |||||||||||||||||||
Purchases | 90 | 43 | 16 | 2 | 151 | ||||||||||||||
Sales | -27 | -27 | -8 | -8 | -70 | ||||||||||||||
Settlements | -11 | 0 | 0 | 0 | -11 | ||||||||||||||
Transfers into Level 3 | 0 | 0 | 11 | 11 | |||||||||||||||
Transfers out of Level 3 | 0 | 0 | -4 | 0 | -4 | ||||||||||||||
Balance as of September 30, 2013 | $ | 245 | $ | 106 | $ | 461 | $ | 11 | $ | 823 | |||||||||
The amount of total gains included in income | |||||||||||||||||||
attributed to the change in unrealized gains related to assets and liabilities held for the nine months ended September 30, 2013 | $ | 1 | $ | 0 | $ | 148 | $ | 0 | $ | 149 | |||||||||
(a) Includes the reclassification of $83 million and $156 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2013, respectively. | |||||||||||||||||||
(b) Includes $11 million of increases in fair value and realized losses due to settlements of $215 million associated with Generation's financial swap contract with ComEd for the nine months ended September 30, 2013. This position eliminates upon consolidation in Exelon's Consolidated Financial Statements. | |||||||||||||||||||
Three Months Ended September 30, 2012 | Nuclear Decommissioning Trust Fund Investments | Pledged Assets for Zion Station Decommissioning | Mark-to-Market Derivatives | Other Investments | Total | ||||||||||||||
Balance as of June 30, 2012 | $ | 54 | $ | 59 | $ | 912 | $ | 17 | $ | 1,042 | |||||||||
Total realized / unrealized gains (losses) | |||||||||||||||||||
Included in net income | 0 | 0 | -112 | (a) | 0 | -112 | |||||||||||||
Included in other comprehensive income | 0 | 0 | -139 | (b) | 0 | -139 | |||||||||||||
Included in noncurrent payables to affiliates | 2 | 0 | 0 | 0 | 2 | ||||||||||||||
Included in payable for Zion Station decommissioning | 0 | 1 | 0 | 0 | 1 | ||||||||||||||
Changes in collateral | 0 | 0 | -15 | 0 | -15 | ||||||||||||||
Purchases, sales, issuances and settlements | |||||||||||||||||||
Purchases | 14 | 4 | 0 | 0 | 18 | ||||||||||||||
Sales | 0 | 0 | 0 | 0 | 0 | ||||||||||||||
Balance as of September 30, 2012 | $ | 70 | $ | 64 | $ | 646 | $ | 17 | $ | 797 | |||||||||
The amount of total losses included in income | |||||||||||||||||||
attributed to the change in unrealized losses related to assets and liabilities held for the three months ended September 30, 2012 | $ | 0 | $ | 0 | $ | -77 | $ | 0 | $ | -77 | |||||||||
Nine Months Ended September 30, 2012 | Nuclear Decommissioning Trust Fund Investments | Pledged Assets for Zion Station Decommissioning | Mark-to-Market Derivatives | Other Investments | Total | ||||||||||||||
Balance as of December 31, 2011 | $ | 13 | $ | 37 | $ | 817 | $ | 0 | $ | 867 | |||||||||
Total realized / unrealized gains (losses) | |||||||||||||||||||
Included in net income | 0 | 0 | -109 | (a) | 0 | -109 | |||||||||||||
Included in other comprehensive income | 0 | 0 | -311 | (b) | 0 | -311 | |||||||||||||
Included in noncurrent payables to affiliates | 2 | 0 | 0 | 2 | |||||||||||||||
Changes in collateral | 0 | 0 | -7 | 0 | -7 | ||||||||||||||
Purchases, sales, issuances and settlements | 0 | ||||||||||||||||||
Purchases | 55 | 36 | 329 | (c) | 17 | 437 | |||||||||||||
Sales | 0 | -9 | 0 | 0 | -9 | ||||||||||||||
Transfers into Level 3 | 0 | 0 | -34 | 0 | -34 | ||||||||||||||
Transfers out of Level 3 | 0 | 0 | -39 | 0 | -39 | ||||||||||||||
Balance as of September 30, 2012 | $ | 70 | $ | 64 | $ | 646 | $ | 17 | $ | 797 | |||||||||
The amount of total gains included in income | |||||||||||||||||||
attributed to the change in unrealized gains related to assets and liabilities held for the nine months ended September 30, 2012 | $ | 0 | $ | 0 | $ | 1 | $ | 0 | $ | 1 | |||||||||
(a) Includes the reclassification of $35 million and $110 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2012, respectively. | |||||||||||||||||||
(b) Includes $35 million of decreases in fair value and $86 million of increases in fair value and realized losses due to settlements of $119 million and $427 million associated with Generation's financial swap contract with ComEd for the three and nine months ended September 30, 2012, respectively. This position was re-designated as a cash flow hedge prior to the merger date. All prospective changes in fair value and reclassifications of realized amounts are being recorded to income offset by the amortization of the frozen mark in OCI. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements. | |||||||||||||||||||
(c) Includes $310 million of fair value from contracts and $14 million of other investments acquired as a result of the merger. | |||||||||||||||||||
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 three and nine months ended September 30, 2013 and 2012: | |||||||||||||||||||
Operating Revenue | Purchased Power and Fuel | Other, net (a) | |||||||||||||||||
Total gains (losses) included in net income for the three months | $ | -39 | $ | 7 | $ | 0 | |||||||||||||
ended September 30, 2013 | |||||||||||||||||||
Total gains (losses) included in net income for the nine months | |||||||||||||||||||
ended September 30, 2013 | $ | -67 | $ | 59 | $ | 2 | |||||||||||||
Change in the unrealized gains relating to assets and liabilities | |||||||||||||||||||
held for the three months ended September 30, 2013 | $ | 42 | $ | 9 | $ | 0 | |||||||||||||
Change in the unrealized gains relating to assets and liabilities | |||||||||||||||||||
held for the nine months ended September 30, 2013 | $ | 71 | $ | 77 | $ | 1 | |||||||||||||
Operating Revenue | Purchased Power and Fuel | Other, net | |||||||||||||||||
Total gains (losses) included in net income for the three months | $ | -116 | $ | 4 | $ | 0 | |||||||||||||
ended September 30, 2012 | |||||||||||||||||||
Total losses included in net income for the nine months | $ | -109 | $ | 0 | $ | 0 | |||||||||||||
ended September 30, 2012 | |||||||||||||||||||
Change in the unrealized gains (losses) relating to assets and | $ | -78 | $ | 1 | $ | 0 | |||||||||||||
liabilities held for the three months ended September 30, 2012 | |||||||||||||||||||
Change in the unrealized gains (losses) relating to assets and | $ | 21 | $ | -20 | $ | 0 | |||||||||||||
liabilities held for the nine months ended September 30, 2012 | |||||||||||||||||||
(a) Other, net activity consists of realized and unrealized gains (losses) included in income for the NDT funds held by Generation. | |||||||||||||||||||
ComEd | |||||||||||||||||||
The following tables present assets and liabilities measured and recorded at fair value on ComEd's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of September 30, 2013 and December 31, 2012: | |||||||||||||||||||
As of September 30, 2013 | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Assets | |||||||||||||||||||
Cash equivalents | $ | 0 | $ | 0 | $ | 0 | $ | 0 | |||||||||||
Rabbi trust investments | |||||||||||||||||||
Mutual funds | 5 | 0 | 0 | 5 | |||||||||||||||
Rabbi trust investments subtotal | 5 | 0 | 0 | 5 | |||||||||||||||
Total assets | 5 | 0 | 0 | 5 | |||||||||||||||
Liabilities | |||||||||||||||||||
Deferred compensation obligation | 0 | -8 | 0 | -8 | |||||||||||||||
Mark-to-market derivative liabilities(a) | 0 | 0 | -122 | -122 | |||||||||||||||
Total liabilities | 0 | -8 | -122 | -130 | |||||||||||||||
Total net assets (liabilities) | $ | 5 | $ | -8 | $ | -122 | $ | -125 | |||||||||||
As of December 31, 2012 | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Assets | |||||||||||||||||||
Cash equivalents | $ | 111 | $ | 0 | $ | 0 | $ | 111 | |||||||||||
Rabbi trust investments | |||||||||||||||||||
Mutual funds | 8 | 0 | 0 | 8 | |||||||||||||||
Rabbi trust investments subtotal | 8 | 0 | 0 | 8 | |||||||||||||||
Total assets | 119 | 0 | 0 | 119 | |||||||||||||||
Liabilities | |||||||||||||||||||
Deferred compensation obligation | 0 | -8 | 0 | -8 | |||||||||||||||
Mark-to-market derivative liabilities(a)(b) | 0 | 0 | -293 | -293 | |||||||||||||||
Total liabilities | 0 | -8 | -293 | -301 | |||||||||||||||
Total net assets (liabilities) | $ | 119 | $ | -8 | $ | -293 | $ | -182 | |||||||||||
(a) The Level 3 balance includes the current and noncurrent liability of $16 million and $106 million at September 30, 2013, respectively, and $18 million and $49 million at December 31, 2012, respectively, related to floating-to-fixed energy swap contracts with unaffiliated suppliers. | |||||||||||||||||||
(b) The Level 3 balance includes the current liability of $226 million at December 31, 2012, related to the fair value of ComEd's financial swap contract with Generation which eliminated upon consolidation in Exelon's Consolidated Financial Statements. | |||||||||||||||||||
The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and nine months ended September 30, 2013 and 2012: | |||||||||||||||||||
Three Months Ended September 30, 2013 | Mark-to-Market Derivatives | ||||||||||||||||||
Balance as of June 30, 2013 | $ | -85 | |||||||||||||||||
Total realized / unrealized gains included in regulatory assets(b) | -37 | ||||||||||||||||||
Balance as of September 30, 2013 | $ | -122 | |||||||||||||||||
Nine Months Ended September 30, 2013 | Mark-to-Market Derivatives | ||||||||||||||||||
Balance as of December 31, 2012 | $ | -293 | |||||||||||||||||
Total realized / unrealized gains included in regulatory assets(a)(b) | 171 | ||||||||||||||||||
Balance as of September 30, 2013 | $ | -122 | |||||||||||||||||
(a) Includes $11 million of decreases in fair value and realized gains due to settlements of $215 million associated with ComEd's financial swap contract with Generation for the nine months ended September 30, 2013. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements. | |||||||||||||||||||
(b) Includes $37 million and $57 million of increases in the fair value and realized losses due to settlements of $1 million and $5 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three and nine months ended September 30, 2013, respectively. | |||||||||||||||||||
Three Months Ended September 30, 2012 | Mark-to-Market Derivatives | ||||||||||||||||||
Balance as of June 30, 2012 | $ | -617 | |||||||||||||||||
Total realized / unrealized gains included in regulatory assets(a)(b) | 195 | ||||||||||||||||||
Balance as of September 30, 2012 | $ | -422 | |||||||||||||||||
Nine Months Ended September 30, 2012 | Mark-to-Market Derivatives | ||||||||||||||||||
Balance as of December 31, 2011 | $ | -800 | |||||||||||||||||
Total realized / unrealized gains included in regulatory assets(a)(b) | 378 | ||||||||||||||||||
Balance as of September 30, 2012 | $ | -422 | |||||||||||||||||
Includes $35 million of increases in fair value and $86 million of decreases in fair value and realized gains due to settlements of $119 million and $427 million of associated with ComEd's financial swap contract with Generation for the three and nine months ended September 30, 2012, respectively. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements. | |||||||||||||||||||
Includes $40 million and $33 million of increases in the fair value and realized losses due to settlements of $1 million and $2 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three and nine months ended September 30, 2012, respectively. | |||||||||||||||||||
PECO | |||||||||||||||||||
The following tables present assets and liabilities measured and recorded at fair value on PECO's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of September 30, 2013 and December 31, 2012: | |||||||||||||||||||
As of September 30, 2013 | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Assets | |||||||||||||||||||
Cash equivalents | $ | 583 | $ | 0 | $ | 0 | $ | 583 | |||||||||||
Rabbi trust investments | |||||||||||||||||||
Mutual funds(a) | 9 | 0 | 0 | 9 | |||||||||||||||
Rabbi trust investments subtotal | 9 | 0 | 0 | 9 | |||||||||||||||
Total assets | 592 | 0 | 0 | 592 | |||||||||||||||
Liabilities | |||||||||||||||||||
Deferred compensation obligation | 0 | -16 | 0 | -16 | |||||||||||||||
Total liabilities | 0 | -16 | 0 | -16 | |||||||||||||||
Total net assets (liabilities) | $ | 592 | $ | -16 | $ | 0 | $ | 576 | |||||||||||
As of December 31, 2012 | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Assets | |||||||||||||||||||
Cash equivalents | $ | 346 | $ | 0 | $ | 0 | $ | 346 | |||||||||||
Rabbi trust investments | |||||||||||||||||||
Mutual funds(a) | 9 | 0 | 0 | 9 | |||||||||||||||
Rabbi trust investments subtotal | 9 | 0 | 0 | 9 | |||||||||||||||
Total assets | 355 | 0 | 0 | 355 | |||||||||||||||
Liabilities | |||||||||||||||||||
Deferred compensation obligation | 0 | -18 | 0 | -18 | |||||||||||||||
Total liabilities | 0 | -18 | 0 | -18 | |||||||||||||||
Total net assets (liabilities) | $ | 355 | $ | -18 | $ | 0 | $ | 337 | |||||||||||
(a) Excludes $14 million and $13 million of the cash surrender value of life insurance investments at September 30, 2013 and December 31, 2012, respectively. | |||||||||||||||||||
PECO had no Level 3 assets or liabilities measured at fair value on a recurring basis during the three and nine months ended September 30, 2013 and 2012. | |||||||||||||||||||
BGE | |||||||||||||||||||
The following tables present assets and liabilities measured and recorded at fair value on BGE's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of September 30, 2013 and December 31, 2012: | |||||||||||||||||||
As of September 30, 2013 | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Assets | |||||||||||||||||||
Cash equivalents | $ | 53 | $ | 0 | $ | 0 | $ | 53 | |||||||||||
Rabbi trust investments | |||||||||||||||||||
Mutual funds(a) | 5 | 0 | 0 | 5 | |||||||||||||||
Rabbi trust investments subtotal | 5 | 0 | 0 | 5 | |||||||||||||||
Total assets | 58 | 0 | 0 | 58 | |||||||||||||||
Liabilities | |||||||||||||||||||
Deferred compensation obligation | 0 | -5 | 0 | -5 | |||||||||||||||
Total liabilities | 0 | -5 | 0 | -5 | |||||||||||||||
Total net assets (liabilities) | $ | 58 | $ | -5 | $ | 0 | $ | 53 | |||||||||||
As of December 31, 2012 | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Assets | |||||||||||||||||||
Cash equivalents | $ | 33 | $ | 0 | $ | 0 | $ | 33 | |||||||||||
Rabbi trust investments | |||||||||||||||||||
Mutual funds | 5 | 0 | 0 | 5 | |||||||||||||||
Rabbi trust investments subtotal | 5 | 0 | 0 | 5 | |||||||||||||||
Total assets | 38 | 0 | 0 | 38 | |||||||||||||||
Liabilities | |||||||||||||||||||
Deferred compensation obligation | 0 | -5 | 0 | -5 | |||||||||||||||
Total liabilities | 0 | -5 | 0 | -5 | |||||||||||||||
Total net assets (liabilities) | $ | 38 | $ | -5 | $ | 0 | $ | 33 | |||||||||||
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 fund Generation's nuclear decommissioning obligations as required by the NRC. The NDT funds hold debt and equity securities directly and indirectly through commingled funds. Generation's investment policies place limitations on the types and investment grade ratings of the securities that may be held by the trusts. These policies limit the trust funds' exposures to investments in highly illiquid markets and other alternative investments. Investments with maturities of three months or less when purchased, including certain short-term fixed income securities are considered cash equivalents and included in the recurring fair value measurements hierarchy as Level 1. | |||||||||||||||||||
With respect to individually held equity securities and exchange traded funds, 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 and exchange traded funds, held directly by the trust funds are based on quoted prices in active markets and are categorized in Level 1. Equity securities held individually and exchange traded funds 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. | |||||||||||||||||||
Equity and fixed income commingled funds and fixed income mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives. The fair values of fixed income commingled and mutual funds held within the trust funds, which generally hold short-term fixed income securities and are not subject to restrictions regarding the purchase or sale of shares, are derived from observable prices. The objectives of the remaining equity commingled funds in which Exelon and Generation invest primarily seek to track the performance of certain equity indices by purchasing equity securities to replicate the capitalization and characteristics of the indices. In general, equity commingled funds are redeemable daily. Equity and fixed income 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. See Note 13 — Nuclear Decommissioning for further discussion on the NDT fund investments. | |||||||||||||||||||
Middle market lending funds are investments in loans or managed funds which invest in private companies. Generation elected the fair value option for its investments held by certain limited partnerships that invest in middle market lending managed funds. The fair value of these loans is determined using a combination of valuation models including cost models, market models, and income models. Investments in middle market lending are categorized as Level 3 because the fair value of these securities is based largely on inputs that are unobservable and utilize complex valuation models. Investments in middle market lending typically cannot be redeemed until maturity of the term loan. | |||||||||||||||||||
Rabbi Trust Investments (Exelon, Generation, ComEd, PECO and BGE). The Rabbi trusts were established to hold assets related to deferred compensation plans existing for certain active and retired members of Exelon's executive management and directors. The investments in the Rabbi trusts are included in investments in the Registrants' Consolidated Balance Sheets. The investments are in fixed-income commingled funds and mutual funds, including short-term investment 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. Fixed-income commingled funds and mutual funds, such as money market funds, are publicly quoted and have been categorized as Level 1 given the clear observability of the prices. | |||||||||||||||||||
Mark-to-Market Derivatives (Exelon, Generation, and ComEd). Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy. Certain derivatives' pricing is verified using indicative price quotations available through brokers or over-the-counter, on-line exchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask, mid-point prices and are obtained from sources that the Registrants believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. This includes consideration of actual transaction volumes, market delivery points, bid-ask spreads and contract duration. The remainder of derivative contracts are valued using the Black model, an industry standard option valuation model. The Black model takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the future prices of energy, interest rates, volatility, credit worthiness and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps and options, model inputs are generally observable. Such instruments are categorized in Level 2. The Registrants' derivatives are predominately at liquid trading points. For derivatives that trade in less liquid markets with limited pricing information model inputs generally would include both observable and unobservable inputs. These valuations may include an estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. Such instruments are categorized in Level 3. | |||||||||||||||||||
Transfers in and out of levels are recognized as of the end of the reporting period the transfer occurred. Given derivatives categorized within Level 1 are valued using exchange-based quoted prices within observable periods, transfers between Level 2 and Level 1 were not material. Transfers into Level 2 from Level 3 generally occur when the contract tenure becomes more observable. Transfers into Level 3 from Level 2 generally occur due to changes in market liquidity or assumptions for certain commodity contracts. | |||||||||||||||||||
Exelon may utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to achieve its targeted level of variable-rate debt as a percent of total debt. In addition, the Registrants may utilize interest rate derivatives to lock in interest rate levels in anticipation of future financings. These interest rate derivatives are typically designated as cash flow hedges. Exelon determines the current fair value by calculating the net present value of expected payments and receipts under the swap agreement, based on and discounted by the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk and other market parameters. As these inputs are based on observable data and valuations of similar instruments, the interest rate swaps are categorized in Level 2 in the fair value hierarchy. See Note 10 — 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 in Level 2 in the fair value hierarchy. | |||||||||||||||||||
Additional Information Regarding Level 3 Fair Value Measurements (Exelon, Generation, ComEd) | |||||||||||||||||||
Mark-to-Market Derivatives (Exelon, Generation, ComEd). For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract tenure extends into unobservable periods. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 as the model inputs generally are not observable. Exelon's RMC approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The RMC is chaired by the chief risk officer and includes the chief financial officer, corporate controller, general counsel, treasurer, vice president of strategy, vice president of audit services and officers representing Exelon's business units. The RMC reports to the Exelon Board of Directors on the scope of the risk management activities and is responsible for approving all valuation procedures at Exelon. Forward price curves for the power market utilized by the front office to manage the portfolio, are reviewed and verified by the middle office, and used for financial reporting by the back office. The Registrants consider credit and nonperformance risk in the valuation of derivative contracts categorized in Level 2 and 3, including both historical and current market data in its assessment of credit and nonperformance risk by counterparty. Due to master netting agreements and collateral posting requirements, the impacts of credit and nonperformance risk were not material to the financial statements. | |||||||||||||||||||
Disclosed below is detail surrounding the Registrants' significant Level 3 valuations. The calculated fair value includes marketability discounts for margining provisions and notional size. Generation's Level 3 balance generally consists of forward sales and purchases of power and natural gas, coal purchases, certain transmission congestion contracts, and project financing debt. Generation utilizes various inputs and factors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors include forward commodity prices, commodity price volatility, contractual volumes, delivery location, interest rates, credit quality of counterparties and credit enhancements. | |||||||||||||||||||
For commodity derivatives, the primary input to the valuation models is the forward commodity price curve for each instrument. Forward commodity price curves are derived by risk management for liquid locations and by the traders and portfolio managers for illiquid locations. All locations are reviewed and verified by risk management considering published exchange transaction prices, executed bilateral transactions, broker quotes, and other observable or public data sources. The relevant forward commodity curve used to value each of the derivatives depends on a number of factors, including commodity type, delivery location, and delivery period. Price volatility varies by commodity and location. When appropriate, Generation discounts future cash flows using risk free interest rates with adjustments to reflect the credit quality of each counterparty for assets and Generation's own credit quality for liabilities. The level of observability of a forward commodity price is generally due to the delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are highly liquid and prices are observable for up to three years in the future. The observability period of volatility is generally shorter than the underlying power curve used in option valuations. The forward curve for a less liquid location is estimated by using the forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not typically represent a majority of the instrument's market price. As a result, the change in fair value is closely tied to liquid market movements and not a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across all Level 3 power and gas delivery locations is generally less than $1.96 and $0.18 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 3. – 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 10 – 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 September 30, 2013 (c) | Valuation Technique | Unobservable Input | Range | |||||||||||||||
Mark-to-market derivatives – Economic Hedges (Generation) (a) | $ | 462 | Discounted Cash Flow | Forward power price | $ | 15 | - | $ | 103 | ||||||||||
Forward gas price | $ | 3.51 | - | $ | 5.97 | ||||||||||||||
Option Model | Volatility percentage | 27 | % | - | 107 | % | |||||||||||||
Mark-to-market derivatives – Proprietary trading (Generation) (a) | $ | 19 | Discounted Cash Flow | Forward power price | $ | 14 | - | $ | 103 | ||||||||||
Option Model | Volatility percentage | 14 | % | - | 28 | % | |||||||||||||
Mark-to-market derivatives (ComEd) | $ | -122 | Discounted Cash Flow | Forward heat rate (b) | 8 | - | 9 | ||||||||||||
Marketability reserve | 3.5 | % | - | 8 | % | ||||||||||||||
Renewable factor | 84 | % | - | 130 | % | ||||||||||||||
The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions. | |||||||||||||||||||
Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract's delivery. | |||||||||||||||||||
The fair values do not include cash collateral held on level three positions of $20 million as of September 30, 2013. | |||||||||||||||||||
Type of trade | Fair Value at December 31, 2012 (d) | Valuation Technique | Unobservable Input | Range | |||||||||||||||
Mark-to-market derivatives – Economic Hedges (Generation) (a) | $ | 473 | Discounted Cash Flow | Forward power price | $ | 14 | - | $ | 79 | ||||||||||
Forward gas price | $ | 3.26 | - | $ | 6.27 | ||||||||||||||
Option Model | Volatility percentage | 28 | % | - | 132 | % | |||||||||||||
Mark-to-market derivatives – Proprietary trading (Generation) (a) | $ | -6 | Discounted Cash Flow | Forward power price | $ | 15 | - | $ | 106 | ||||||||||
Option Model | Volatility percentage | 16 | % | - | 48 | % | |||||||||||||
Mark-to-market derivatives - Transactions with Affiliates (Generation and ComEd) (b) | $ | 226 | Discounted Cash Flow | Marketability reserve | 8 | % | - | 9 | % | ||||||||||
Mark-to-market derivatives (ComEd) | $ | -67 | Discounted Cash Flow | Forward heat rate (c) | 8 | - | 9.5 | ||||||||||||
Marketability reserve | 3.5 | % | - | 8.3 | % | ||||||||||||||
Renewable factor | 81 | % | - | 123 | % | ||||||||||||||
The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions. | |||||||||||||||||||
Includes current assets for Generation and current liabilities for ComEd of $226 million, related to the fair value of the five-year financial swap contract between Generation and ComEd, which eliminates in consolidation. | |||||||||||||||||||
Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract's delivery. | |||||||||||||||||||
The fair values do not include cash collateral held on level three positions of $33 million as of December 31, 2012. | |||||||||||||||||||
The inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted. The significant unobservable inputs used in the fair value measurement of Generation's commodity derivatives are forward commodity prices and for options is 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, the fair value of these loans is determined using a combination of valuations 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 applications of discounts or premiums applied to the prices of comparable companies for factors such as size, marketability and relative performance. | |||||||||||||||||||
Because Generation relies on third-party fund managers to develop the quantitative unobservable inputs without adjustment for the valuations of its' middle market lending, 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' middle market lending, Generation reviewed independent valuations and reviewed the assumptions in the detailed pricing models used by the fund managers. | |||||||||||||||||||
As of September 30, 2013, Generation has outstanding commitments to invest in middle market lending of approximately $192 million. These commitments will be funded by Generation's existing nuclear decommissioning trust funds. | |||||||||||||||||||
Exelon Generation Co L L C [Member] | ' | ||||||||||||||||||
Fair Value of Financial Assets and Liabilities [Line Items] | ' | ||||||||||||||||||
Fair Value of Financial Assets and Liabilities (Exelon, Generation, ComEd, PECO and BGE) | ' | ||||||||||||||||||
The level 3 balance includes current assets for Generation of $226 million at December 31, 2012, related to the fair value of Generation's financial swap contract with ComEd, which eliminates upon consolidation in Exelon's Consolidated Financial Statements. |
Derivative_Financial_Instrumen
Derivative Financial Instruments (Exelon, Generation, ComEd, PECO and BGE) | 9 Months Ended | |||||||||||||||||||||||||||||||||||||
Sep. 30, 2013 | ||||||||||||||||||||||||||||||||||||||
Derivative Financial Instruments [Line Items] | ' | |||||||||||||||||||||||||||||||||||||
Derivative Financial Instruments (Exelon, Generation, ComEd, PECO and BGE) | ' | |||||||||||||||||||||||||||||||||||||
10. Derivative Financial Instruments (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||||||||||||||||||||||||
The Registrants are exposed to certain risks related to ongoing business operations. The primary risks managed by using derivative instruments are commodity price risk and interest rate risk. | ||||||||||||||||||||||||||||||||||||||
Commodity Price Risk (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||||||||||||||||||||||||
To the extent the amount of energy Exelon generates differs from the amount of energy it has contracted to sell, the Registrants are exposed to market fluctuations in the prices of electricity, fossil fuels and other commodities. The Registrants employ established policies and procedures to manage their risks associated with market fluctuations by entering into physical and financial derivative contracts, including swaps, futures, forwards, options and short-term and long-term commitments to purchase and sell energy and energy-related products. The Registrants believe these instruments, which are classified as either economic hedges or non-derivatives, mitigate exposure to fluctuations in commodity prices. | ||||||||||||||||||||||||||||||||||||||
Derivative accounting guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings each period. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include normal purchase normal sale (NPNS), cash flow hedge, and fair value hedge. For commodity transactions, effective with the date of merger with Constellation, Generation no longer utilizes the special election provided for by the cash flow hedge designation and de-designated all of its existing cash flow hedges prior to the merger. Because the underlying forecasted transactions remain at least reasonably possible, the fair value of the effective portion of these cash flow hedges was frozen in accumulated OCI and reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurs, or becomes probable of not occurring. None of Constellation's designated cash flow hedges for commodity transactions prior to the merger were re-designated as cash flow hedges. The effect of this decision is that all derivative economic hedges for commodities are recorded at fair value through earnings for the combined company, referred to as economic hedges in the following tables. The Registrants have applied the NPNS scope exception to certain derivative contracts for the forward sale of generation, power procurement agreements, and natural gas supply agreements. Non-derivative contracts for access to additional generation and certain sales to load-serving entities are accounted for primarily under the accrual method of accounting, which is further discussed in Note 19 – Commitments and Contingencies of the Exelon 2012 Form 10-K. Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading activities are a complement to Generation's energy marketing portfolio but represent a small portion of Generation's overall energy marketing activities. | ||||||||||||||||||||||||||||||||||||||
Economic Hedging. The Registrants are exposed to commodity price risk primarily relating to changes in the market price of electricity, fossil fuels, and other commodities associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies, and other factors. Within Exelon, Generation has the most exposure to commodity price risk. Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power sales, fuel and energy purchases, natural gas transportation and pipeline capacity agreements and other energy-related products marketed and purchased. In order to manage these risks, Generation may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from forecasted sales of energy and purchases of fuel and energy. The objectives for entering into such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return on electric generation operations, fixing the price of a portion of anticipated fuel purchases for the operation of power plants, and fixing the price for a portion of anticipated energy purchases to supply load-serving customers. The portion of forecasted transactions hedged may vary based upon management's policies and hedging objectives, the market, weather conditions, operational and other factors. Generation is also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis. | ||||||||||||||||||||||||||||||||||||||
In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation's owned and contracted generation positions that have not been hedged. Generation hedges commodity price risk on a ratable basis over three-year periods. As of September 30, 2013, the percentage of expected generation hedged for the major reportable segments was 97%-100%, 84%-87%, and 48%-51% for 2013, 2014, and 2015, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted capacity. Equivalent sales represent all hedging products, which include economic hedges and certain non-derivative contracts including, Generation's sales to ComEd, PECO and BGE to serve their retail load. | ||||||||||||||||||||||||||||||||||||||
In order to fulfill a requirement of the Illinois Settlement Legislation, Generation and ComEd entered into a five-year financial swap contract that expired May 31, 2013. The financial swap was designed to hedge spot market purchases, which, along with ComEd's remaining energy procurement contracts, met its load service requirements. The terms of the financial swap contract required Generation to pay the around-the-clock market price for a portion of ComEd's electricity supply requirement, while ComEd paid a fixed price. | ||||||||||||||||||||||||||||||||||||||
As the contract expired May 31, 2013, all realized impacts have been included in Generation's and ComEd's results of operations. In Exelon's consolidated financial statements, all financial statement effects of the financial swap recorded by Generation and ComEd are eliminated. | ||||||||||||||||||||||||||||||||||||||
In addition, the physical contracts that Generation has entered into with ComEd and that ComEd has entered into with Generation and other suppliers as part of the ComEd power procurement process, which are further discussed in Note 3 – Regulatory Matters of the Exelon 2012 Form 10-K qualify and are accounted for under the NPNS exception. Based on the Illinois Settlement Legislation and ICC-approved procurement methodologies permitting ComEd to recover its electricity procurement costs from retail customers with no mark-up, ComEd's price risk related to power procurement is limited. | ||||||||||||||||||||||||||||||||||||||
On December 17, 2010, ComEd entered into several 20-year floating-to-fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. Delivery under the contracts began in June 2012. Pursuant to the ICC's Order on December 19, 2012, ComEd's commitments under the existing long-term contracts for energy and associate RECs were reduced in the first quarter of 2013. These contracts are designed to lock in a portion of the long-term commodity price risk resulting from the renewable energy resource procurement requirements in the Illinois Settlement Legislation. ComEd has not elected hedge accounting for these derivative financial instruments. ComEd records the fair value of the swap contracts on its balance sheet. Because ComEd receives full cost recovery for energy procurement and related costs from retail customers, the change in fair value each period is recorded by ComEd as a regulatory asset or liability. See Note 5 – 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 5 - Regulatory Matters. Based on Pennsylvania legislation and the DSP Programs permitting PECO to recover its electric supply procurement costs from retail customers with no mark-up, PECO's price risk related to electric supply procurement is limited. PECO locked in fixed prices for a significant portion of its commodity price risk through full requirements contracts and block contracts. PECO has certain full requirements contracts and block contracts that are considered derivatives and qualify for the NPNS scope exception under current derivative authoritative guidance. | ||||||||||||||||||||||||||||||||||||||
PECO's natural gas procurement policy is designed to achieve a reasonable balance of long-term and short-term gas purchases under different pricing approaches in order to achieve system supply reliability at the least cost. PECO's reliability strategy is two-fold. First, PECO must assure that there is sufficient transportation capacity to satisfy delivery requirements. Second, PECO must ensure that a firm source of supply exists to utilize the capacity resources. All of PECO's natural gas supply and asset management agreements that are derivatives either qualify for the NPNS scope exception and have been designated as such, or have no mark-to-market balances because the derivatives are index priced. Additionally, in accordance with the 2013 PAPUC PGC settlement and to reduce the exposure of PECO and its customers to natural gas price volatility, PECO has continued its program to purchase natural gas for both winter and summer supplies using a layered approach of locking-in prices ahead of each season with long-term gas purchase agreements (those with primary terms of at least twelve months). Under the terms of the 2013 PGC settlement, PECO is required to lock in (i.e., economically hedge) the price of a minimum volume of its long-term gas commodity purchases. PECO's gas-hedging program is designed to cover about 30% of planned natural gas purchases in support of projected firm sales. The hedging program for natural gas procurement has no direct impact on PECO's financial position or results of operations as natural gas costs are fully recovered from customers under the PGC. | ||||||||||||||||||||||||||||||||||||||
BGE has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC. The SOS rates charged recover BGE's wholesale power supply costs and include an administrative fee. The administrative fee includes an incremental cost component and a shareholder return component for commercial and industrial rate classes. BGE's price risk related to electric supply procurement is limited. BGE locks in fixed prices for all of its SOS requirements through full requirements contracts. Certain of BGE's full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other BGE full requirements contracts are not derivatives. | ||||||||||||||||||||||||||||||||||||||
BGE provides natural gas to its customers under a MBR mechanism approved by the MDPSC. Under this mechanism, BGE's actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between BGE's actual cost and the market index is shared equally between shareholders and customers. BGE must also secure fixed price contracts for at least 10%, but not more than 20%, of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period. These fixed-price contracts are not subject to sharing under the MBR mechanism. BGE also ensures it has sufficient pipeline transportation capacity to meet customer requirements. All of BGE's natural gas supply and asset management agreements qualify for the NPNS 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 2,499 GWhs and 6,066 GWhs for the three and nine months ended September 30, 2013, respectively, and 4,352 GWhs and 9,981 GWhs for the three and nine months ended September 30, 2012, respectively, 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 September 30, 2013, Exelon had $1,250 million of notional amounts of fixed-to-floating hedges outstanding and $213 million of notional amounts of floating-to-fixed hedges outstanding. Assuming the fair value and cash flow interest rate hedges are 100% effective, a hypothetical 50 bps increase in the interest rates associated with unhedged variable-rate debt (excluding Commercial Paper) and fixed-to-floating swaps would result in approximately a $1 million decrease in Exelon Consolidated pre-tax income for the nine months ended September 30, 2013. To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are typically designated as economic hedges. Below is a summary of the interest rate and foreign currency hedges as of September 30, 2013. | ||||||||||||||||||||||||||||||||||||||
Generation | Other | Exelon | ||||||||||||||||||||||||||||||||||||
Description | Derivatives Designated as Hedging Instruments | Economic Hedges | Proprietary Trading (a) | Collateral and Netting (b) | Subtotal | Derivatives Designated as Hedging Instruments | Total | |||||||||||||||||||||||||||||||
Mark-to-market derivative assets (Current Assets) | $ | - | $ | 3 | $ | 18 | $ | -19 | $ | 2 | $ | - | $ | 2 | ||||||||||||||||||||||||
Mark-to-market derivative assets (Noncurrent Assets) | 27 | 5 | 17 | -16 | 33 | 13 | 46 | |||||||||||||||||||||||||||||||
Total mark-to-market derivative assets | $ | 27 | $ | 8 | $ | 35 | $ | -35 | $ | 35 | $ | 13 | $ | 48 | ||||||||||||||||||||||||
Mark-to-market derivative liabilities (Current Liabilities) | $ | -1 | $ | -1 | $ | -19 | $ | 19 | $ | -2 | $ | - | $ | -2 | ||||||||||||||||||||||||
Mark-to-market derivative liabilities (Noncurrent liabilities) | -14 | - | -16 | 16 | -14 | - | -14 | |||||||||||||||||||||||||||||||
Total mark-to-market derivative liabilities | $ | -15 | $ | -1 | $ | -35 | $ | 35 | $ | -16 | $ | - | $ | -16 | ||||||||||||||||||||||||
Total mark-to-market derivative net assets (liabilities) | $ | 12 | $ | 7 | $ | 0 | $ | 0 | $ | 19 | $ | 13 | $ | 32 | ||||||||||||||||||||||||
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 interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates. | ||||||||||||||||||||||||||||||||||||||
Represents the netting of fair value balances with the same counterparty and any associated cash collateral. | ||||||||||||||||||||||||||||||||||||||
The following table provides a summary of the interest rate hedge balances recorded by the Registrants as of December 31, 2012: | ||||||||||||||||||||||||||||||||||||||
Generation | Other | Exelon | ||||||||||||||||||||||||||||||||||||
Description | Derivatives Designated as Hedging Instruments | Economic Hedges | Proprietary Trading (a) | Collateral and Netting (b) | Subtotal | Derivatives Designated as Hedging Instruments | Total | |||||||||||||||||||||||||||||||
Mark-to-market derivative assets (Current Assets) | $ | - | $ | 3 | $ | 20 | $ | -19 | $ | 4 | $ | - | $ | 4 | ||||||||||||||||||||||||
Mark-to-market derivative assets (Noncurrent Assets) | 38 | 8 | 32 | -32 | 46 | 13 | 59 | |||||||||||||||||||||||||||||||
Total mark-to-market derivative assets | $ | 38 | $ | 11 | $ | 52 | $ | -51 | $ | 50 | $ | 13 | $ | 63 | ||||||||||||||||||||||||
Mark-to-market derivative liabilities (Current Liabilities) | $ | -1 | $ | -1 | $ | -19 | $ | 19 | $ | -2 | $ | - | $ | -2 | ||||||||||||||||||||||||
Mark-to-market derivative liabilities (Noncurrent liabilities) | -31 | - | -32 | 32 | -31 | - | -31 | |||||||||||||||||||||||||||||||
Total mark-to-market derivative liabilities | -32 | -1 | -51 | 51 | -33 | - | -33 | |||||||||||||||||||||||||||||||
Total mark-to-market derivative net assets (liabilities) | $ | 6 | $ | 10 | $ | 1 | $ | - | $ | 17 | $ | 13 | $ | 30 | ||||||||||||||||||||||||
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: | ||||||||||||||||||||||||||||||||||||||
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 interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates. | ||||||||||||||||||||||||||||||||||||||
Represents the netting of fair value balances with the same counterparty and any associated cash collateral. | ||||||||||||||||||||||||||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||||||||||||||||||||||||
30-Sep-13 | 30-Sep-13 | |||||||||||||||||||||||||||||||||||||
Gain (Loss) on Swaps | Gain (Loss) on Borrowings | Gain (Loss) on Swaps | Gain (Loss) on Borrowings | |||||||||||||||||||||||||||||||||||
Generation (a) | Exelon | Generation | Exelon | Generation (a) | Exelon | Generation | Exelon | |||||||||||||||||||||||||||||||
$ | -4 | $ | 4 | $ | -1 | $ | -5 | $ | -13 | $ | 1 | $ | 0 | $ | -2 | |||||||||||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||||||||||||||||||||||||
30-Sep-12 | 30-Sep-12 | |||||||||||||||||||||||||||||||||||||
Gain (Loss) on Swaps | Gain (Loss) on Borrowings | Gain (Loss) on Swaps | Gain (Loss) on Borrowings | |||||||||||||||||||||||||||||||||||
Generation | Exelon | Generation | Exelon | Generation | Exelon | Generation | Exelon | |||||||||||||||||||||||||||||||
$ | -1 | $ | 0 | $ | -3 | $ | 0 | $ | -3 | $ | -2 | $ | -6 | $ | 2 | |||||||||||||||||||||||
__________ | ||||||||||||||||||||||||||||||||||||||
For the three and nine months ended September 30, 2013, the loss on Generation swaps included $4 million and $12 million, respectively, realized in earnings, with an immaterial amount excluded from hedge effectiveness testing. | ||||||||||||||||||||||||||||||||||||||
During the third quarter of 2013, Exelon entered into $450 million of notional amounts of fixed-to-floating fair value hedges related to interest rate swaps, which expire in 2020. At September 30, 2013, Exelon and Generation had total outstanding fixed-to-floating fair value hedges related to interest rate swaps of $1,100 million and $550 million, with unrealized gains of $40 million and $27 million, respectively. At December 31, 2012, Exelon and Generation had outstanding fixed-to-floating fair value hedges related to interest rate swaps of $650 million and $550 million that expire in 2015, with unrealized gains of $49 million and $38 million, respectively. During the nine months ended September 30, 2013 and 2012, the impact on the results of operations as a result of ineffectiveness from fair value hedges was a $1 million gain and immaterial, respectively. | ||||||||||||||||||||||||||||||||||||||
Cash Flow Hedges. In anticipation of the Continental Wind, LLC non-recourse project financing that was completed on September 30, 2013, Exelon entered into forward starting interest rate swaps that were designated as cash flow hedges to hedge the change in benchmark interest rates. Upon settlement of the swaps, a $26 million effective gain in OCI was deferred and will be amortized into interest expense over the life of the debt. See Note 11 – Debt and Credit Agreements for additional information on the project financing. | ||||||||||||||||||||||||||||||||||||||
In connection with the DOE guaranteed loan for the Antelope Valley acquisition, as discussed in Note 11 – Debt and Credit Agreements, Generation entered into a floating-to-fixed forward starting interest rate swap with a notional amount of $485 million and a mandatory early termination date of April 5, 2014. The swap hedges approximately 75% of Generation's future interest rate exposure associated with the financing and was designated as a cash flow hedge. As such, the effective portion of the hedge is recorded in other comprehensive income within Generation's Consolidated Balance Sheets, with any ineffectiveness recorded in Generation's Consolidated Statements of Operations and Comprehensive Income. Net gains (or losses) from settlement of the hedges, to the extent effective, are amortized as an adjustment to the interest expense over the term of the DOE guaranteed loan. | ||||||||||||||||||||||||||||||||||||||
Every time Generation draws down on the loan, an offsetting hedge (fixed-to-floating) is executed and a portion of the cash flow hedge, with a notional amount equal to the offsetting hedge, is de-designated and the related gains or losses going forward are reflected in earnings, which are largely offset by the losses or gains in the offsetting hedge. | ||||||||||||||||||||||||||||||||||||||
Antelope Valley received its first loan advance on April 5, 2012, and a series of additional advances subsequently. Generation has entered into a series of fixed-to-floating interest rate swaps with an aggregated notional amount of $328 million, approximately 75% of the loan advance amount to offset portions of the original interest rate hedge, which are not designated as cash flow hedges. The remaining cash flow hedge has a notional amount of $156 million. At September 30, 2013, Generation's mark-to-market non-current derivative liability relating to the interest rate swaps in connection with the loan agreement to fund Antelope Valley was $13 million. | ||||||||||||||||||||||||||||||||||||||
During the third quarter of 2011, a subsidiary of Constellation entered into floating-to-fixed interest rate swaps to manage a portion of the interest rate exposure for anticipated long-term borrowings to finance Sacramento PV Energy. The swaps have a total notional amount of $29 million as of September 30, 2013 and expire in 2027. After the closing of the merger with Constellation, the swaps were re-designated as cash flow hedges. At September 30, 2013, the subsidiary had a $2 million non-current derivative liability related to these swaps. | ||||||||||||||||||||||||||||||||||||||
During the third quarter of 2012, a subsidiary of Exelon Generation entered into a floating-to-fixed interest rate swap to manage a portion of the interest rate exposure of anticipated long-term borrowings to finance Constellation Solar Horizons. The swap has a notional amount of $28 million as of September 30, 2013 and expires in 2030. This swap is designated as a cash flow hedge. At September 30, 2013, the subsidiary had a $2 million non-current derivative asset related to the swap. | ||||||||||||||||||||||||||||||||||||||
During the nine months ended September 30, 2013 and 2012, the impact on the results of operations as a result of ineffectiveness from cash flow hedges was immaterial. | ||||||||||||||||||||||||||||||||||||||
Economic Hedges. At September 30, 2013, Generation had $134 million in notional amounts of interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions and $38 million in notional amounts of foreign currency exchange rate swaps that are marked-to-market to manage the exposure associated with international purchases of commodities in currencies other than U.S. dollars. | ||||||||||||||||||||||||||||||||||||||
At September 30, 2013, Exelon and Generation had $150 million in notional amounts of fixed-to-floating interest rate swaps that are marked-to-market, with unrealized gains of $3 million. These swaps, which were acquired as part of the merger with Constellation, expire in 2014. During the nine months ended September 30, 2013 and the period from March 12 to September 30, 2012, the impact on the results of operations was immaterial. | ||||||||||||||||||||||||||||||||||||||
Fair Value Measurement and Accounting for the Offsetting of Amounts Related to Certain Contracts (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||||||||||||||||||||||||
Fair value accounting guidance and disclosures about offsetting assets and liabilities requires the fair value of derivative instruments to be shown in the Notes to the Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheet. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referencing contracts via one payment stream, which takes place either as the contracts deliver, when collateral is requested or in the event of default. Generation's use of cash collateral is generally unrestricted unless Generation is downgraded below investment grade (i.e. to BB+ or Ba1). In the table below, Generation's energy related economic hedges and proprietary trading derivatives are shown gross and the impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, is aggregated in the collateral and netting column. As of September 30, 2013 and December 31, 2012, $5 million of cash collateral posted and $3 million of cash collateral received, respectively, was not offset against derivative positions because such collateral was not associated with any energy-related derivatives or as of the balance sheet date there were no positions to offset. Excluded from the tables below are economic hedges that qualify for the NPNS scope exception and other non-derivative contracts that are accounted for under the accrual method of accounting. | ||||||||||||||||||||||||||||||||||||||
ComEd's use of cash collateral is generally unrestricted unless ComEd is downgraded below investment grade (i.e. to BB+ or Ba1). | ||||||||||||||||||||||||||||||||||||||
Cash collateral held by PECO and BGE must be deposited in a non affiliate major U.S. commercial bank or foreign bank with a U.S. branch office that meet certain qualifications. | ||||||||||||||||||||||||||||||||||||||
The following table provides a summary of the derivative fair value balances recorded by the Registrants as of September 30, 2013: | ||||||||||||||||||||||||||||||||||||||
Generation | ComEd | Exelon | ||||||||||||||||||||||||||||||||||||
Economic | Proprietary | Collateral and | Economic | Total | ||||||||||||||||||||||||||||||||||
Derivatives | Hedges | Trading | Netting (a) | Subtotal (b) | Hedges (c) | Derivatives | ||||||||||||||||||||||||||||||||
Mark-to-market | ||||||||||||||||||||||||||||||||||||||
derivative assets (current assets) | $ | 2,244 | $ | 1,577 | $ | -3,093 | $ | 728 | $ | 0 | $ | 728 | ||||||||||||||||||||||||||
Mark-to-market | ||||||||||||||||||||||||||||||||||||||
derivative assets (noncurrent assets) | 1,540 | 447 | -1,254 | 733 | 0 | 733 | ||||||||||||||||||||||||||||||||
Total mark-to-market | ||||||||||||||||||||||||||||||||||||||
derivative assets | $ | 3,784 | $ | 2,024 | $ | -4,347 | $ | 1,461 | $ | 0 | $ | 1,461 | ||||||||||||||||||||||||||
Mark-to-market | ||||||||||||||||||||||||||||||||||||||
derivative liabilities (current liabilities) | $ | -1,812 | $ | -1,538 | $ | 3,242 | $ | -108 | $ | -16 | $ | -124 | ||||||||||||||||||||||||||
Mark-to-market | ||||||||||||||||||||||||||||||||||||||
derivative liabilities (noncurrent liabilities) | -911 | -438 | 1,251 | -98 | -106 | -204 | ||||||||||||||||||||||||||||||||
Total mark-to-market | ||||||||||||||||||||||||||||||||||||||
derivative liabilities | $ | -2,723 | $ | -1,976 | $ | 4,493 | $ | -206 | $ | -122 | $ | -328 | ||||||||||||||||||||||||||
Total mark-to-market | ||||||||||||||||||||||||||||||||||||||
derivative net assets (liabilities) | $ | 1,061 | $ | 48 | $ | 146 | $ | 1,255 | $ | -122 | $ | 1,133 | ||||||||||||||||||||||||||
__________ | ||||||||||||||||||||||||||||||||||||||
(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 $86 million and $8 million, respectively, and current and noncurrent liabilities are shown net of collateral of $(235) million and $(5) million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $146 million at September 30, 2013. | ||||||||||||||||||||||||||||||||||||||
(c) Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers. | ||||||||||||||||||||||||||||||||||||||
The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2012: | ||||||||||||||||||||||||||||||||||||||
Generation | ComEd | Exelon | ||||||||||||||||||||||||||||||||||||
Economic | Proprietary | Collateral and | Economic | Intercompany | Total | |||||||||||||||||||||||||||||||||
Derivatives | Hedges (a) | Trading | Netting(b) | Subtotal (c) | Hedges (a) (d) | Eliminations (a) | Derivatives | |||||||||||||||||||||||||||||||
Mark-to-market | ||||||||||||||||||||||||||||||||||||||
derivative assets (current assets) | $ | 2,883 | $ | 2,469 | $ | -4,418 | $ | 934 | $ | 0 | $ | 0 | $ | 934 | ||||||||||||||||||||||||
Mark-to-market | ||||||||||||||||||||||||||||||||||||||
derivative assets with affiliate (current assets) | 226 | 0 | 0 | 226 | 0 | -226 | 0 | |||||||||||||||||||||||||||||||
Mark-to-market | ||||||||||||||||||||||||||||||||||||||
derivative assets (noncurrent assets) | 1,792 | 724 | -1,638 | 878 | 0 | 0 | 878 | |||||||||||||||||||||||||||||||
Mark-to-market | ||||||||||||||||||||||||||||||||||||||
Total mark-to-market | ||||||||||||||||||||||||||||||||||||||
derivative assets | $ | 4,901 | $ | 3,193 | $ | -6,056 | $ | 2,038 | $ | 0 | $ | -226 | $ | 1,812 | ||||||||||||||||||||||||
Mark-to-market | ||||||||||||||||||||||||||||||||||||||
derivative liabilities (current liabilities) | $ | -2,419 | $ | -2,432 | $ | 4,519 | $ | -332 | $ | -18 | $ | 0 | $ | -350 | ||||||||||||||||||||||||
Mark-to-market | ||||||||||||||||||||||||||||||||||||||
derivative liability with affiliate (current liabilities) | 0 | 0 | 0 | 0 | -226 | 226 | 0 | |||||||||||||||||||||||||||||||
Mark-to-market | ||||||||||||||||||||||||||||||||||||||
derivative liabilities (noncurrent liabilities) | -1,080 | -689 | 1,568 | -201 | -49 | 0 | -250 | |||||||||||||||||||||||||||||||
Mark-to-market | ||||||||||||||||||||||||||||||||||||||
Total mark-to-market | ||||||||||||||||||||||||||||||||||||||
derivative liabilities | $ | -3,499 | $ | -3,121 | $ | 6,087 | $ | -533 | $ | -293 | $ | 226 | $ | -600 | ||||||||||||||||||||||||
Total mark-to-market | ||||||||||||||||||||||||||||||||||||||
derivative net assets (liabilities) | $ | 1,402 | $ | 72 | $ | 31 | $ | 1,505 | $ | -293 | $ | 0 | $ | 1,212 | ||||||||||||||||||||||||
__________ | ||||||||||||||||||||||||||||||||||||||
(a) Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $226 million related to the fair value of the five-year financial swap contract between Generation and ComEd, as described above. For Generation excludes $28 million of noncurrent liability relating to an interest rate swap in connection with a loan agreement to fund Antelope Valley as discussed above. | ||||||||||||||||||||||||||||||||||||||
(b) Exelon and Generation net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, and letters of credit. These are not reflected in the table above. | ||||||||||||||||||||||||||||||||||||||
(c) Current and noncurrent assets are shown net of collateral of $113 million and $201 million, respectively, and current and noncurrent liabilities are shown net of collateral of $ (214) million and $ (131) million, respectively. The total cash collateral received, net of cash collateral posted and offset against mark-to-market assets and liabilities was $31 million at December 31, 2012. | ||||||||||||||||||||||||||||||||||||||
(d) Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers. | ||||||||||||||||||||||||||||||||||||||
Cash Flow Hedges (Exelon, Generation and ComEd). As discussed previously, effective prior to the merger with Constellation, Generation de-designated all of its cash flow hedges relating to commodity price risk. Because the underlying forecasted transactions remain at least reasonably possible, the fair value of the effective portion of these cash flow hedges was frozen in accumulated OCI and is reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurs, or becomes probable of not occurring. Generation began recording prospective changes in the fair value of these instruments through current earnings from the date of de-designation. Approximately $271 million of these net pre-tax unrealized gains within accumulated OCI are expected to be reclassified from accumulated OCI during the next twelve months by Generation. Generation expects the settlement of the majority of its cash flow hedges will occur during 2013 through 2014. | ||||||||||||||||||||||||||||||||||||||
Exelon discontinues hedge accounting prospectively when it determines that the derivative is no longer effective in offsetting changes in the cash flows of a hedged item or when it is no longer probable that the forecasted transaction will occur. For the three months ended September 30, 2013 and 2012, amounts reclassified into earnings as a result of the discontinuance of cash flow hedges were immaterial. | ||||||||||||||||||||||||||||||||||||||
The tables below provide the activity of accumulated OCI related to cash flow hedges for the three and nine months ended September 30, 2013 and 2012, containing information about the changes in the fair value of cash flow hedges and the reclassification from accumulated OCI into results of operations. The amounts reclassified from accumulated OCI, when combined with the impacts of the actual physical power sales, result in the ultimate recognition of net revenues at the contracted price. | ||||||||||||||||||||||||||||||||||||||
Total Cash Flow Hedge OCI Activity, Net of Income Tax | ||||||||||||||||||||||||||||||||||||||
Generation | Exelon | |||||||||||||||||||||||||||||||||||||
Three Months Ended September 30, 2013 | Income Statement Location | Energy-Related Hedges | Total Cash Flow Hedges | |||||||||||||||||||||||||||||||||||
Accumulated OCI derivative gain at June 30, 2013 | $ | 255 | (a) | $ | 245 | |||||||||||||||||||||||||||||||||
Effective portion of changes in fair value | 0 | 2 | (b) | |||||||||||||||||||||||||||||||||||
Reclassifications from accumulated OCI to net income | Operating Revenues | -51 | -48 | |||||||||||||||||||||||||||||||||||
Accumulated OCI derivative gain at September 30, 2013 | $ | 204 | (a) | $ | 199 | |||||||||||||||||||||||||||||||||
(a) Excludes $11 million of losses, net of taxes, related to interest rate swaps and treasury rate locks as of September 30, 2013 and June 30, 2013. | ||||||||||||||||||||||||||||||||||||||
(b) Includes $2 million of gains, net of taxes, related to the effective portion of changes in fair value of interest rate swaps and treasury rate locks. | ||||||||||||||||||||||||||||||||||||||
Total Cash Flow Hedge OCI Activity, Net of Income Tax | ||||||||||||||||||||||||||||||||||||||
Generation | Exelon | |||||||||||||||||||||||||||||||||||||
Nine Months Ended September 30, 2013 | Income Statement Location | Energy-Related Hedges | Total Cash Flow Hedges | |||||||||||||||||||||||||||||||||||
Accumulated OCI derivative gain at December 31, 2012 | $ | 532 | (a)(c) | $ | 368 | |||||||||||||||||||||||||||||||||
Effective portion of changes in fair value | 0 | 25 | (d) | |||||||||||||||||||||||||||||||||||
Reclassifications from accumulated OCI to net income | Operating Revenues | -328 | (b) | -194 | ||||||||||||||||||||||||||||||||||
Accumulated OCI derivative gain at September 30, 2013 | $ | 204 | (c) | $ | 199 | |||||||||||||||||||||||||||||||||
__________ | ||||||||||||||||||||||||||||||||||||||
(a) Includes $133 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, as of December 31, 2012. | ||||||||||||||||||||||||||||||||||||||
(b) Includes $133 million of losses, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd. | ||||||||||||||||||||||||||||||||||||||
(c) Excludes $11 million of losses and $20 million of losses, net of taxes, related to interest rate swaps and treasury locks as of September 30, 2013 and December 31, 2012, respectively. | ||||||||||||||||||||||||||||||||||||||
(d) Includes $25 million of losses, net of taxes, related to the effective portion of changes in fair value of interest rate swaps and treasury rate locks. | ||||||||||||||||||||||||||||||||||||||
Total Cash Flow Hedge OCI Activity, Net of Income Tax | ||||||||||||||||||||||||||||||||||||||
Generation | Exelon | |||||||||||||||||||||||||||||||||||||
Three Months Ended September 30, 2012 | Income Statement Location | Energy-Related Hedges | Total Cash Flow Hedges | |||||||||||||||||||||||||||||||||||
Accumulated OCI derivative gain at June 30, 2012 | $ | 923 | (a)(c) | $ | 547 | |||||||||||||||||||||||||||||||||
Effective portion of changes in fair value | - | (e) | - | (d) | ||||||||||||||||||||||||||||||||||
Reclassifications from accumulated OCI to net income | Operating Revenues | -171 | (b) | -88 | ||||||||||||||||||||||||||||||||||
Accumulated OCI derivative gain at September 30, 2012 | $ | 752 | (a)(c) | $ | 459 | |||||||||||||||||||||||||||||||||
. | ||||||||||||||||||||||||||||||||||||||
(a) Includes $232 million and $315 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd as of September 30, 2012 and June 30, 2012, respectively. | ||||||||||||||||||||||||||||||||||||||
(b) Includes a $83 million of losses, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd. | ||||||||||||||||||||||||||||||||||||||
(c) Excludes $22 million of losses and $22 million of gains, net of taxes, related to interest rate swaps and treasury rate locks for the three months ended September 30, 2012 and June 30, 2012 respectively. | ||||||||||||||||||||||||||||||||||||||
(d) Includes $0 million of losses, net of taxes, at Generation related to the effective portion of changes in fair value of interest rate swaps and treasury rate locks. | ||||||||||||||||||||||||||||||||||||||
(e) Due to de-designation of all commodity cash flow positions prior to the merger date, there are no changes in fair value. | ||||||||||||||||||||||||||||||||||||||
Total Cash Flow Hedge OCI Activity, Net of Income Tax | ||||||||||||||||||||||||||||||||||||||
Generation | Exelon | |||||||||||||||||||||||||||||||||||||
Nine Months Ended September 30, 2012 | Income Statement Location | Energy-Related Hedges | Total Cash Flow Hedges | |||||||||||||||||||||||||||||||||||
Accumulated OCI derivative gain at December 31, 2011 | $ | 925 | (a)(c) | $ | 488 | |||||||||||||||||||||||||||||||||
Effective portion of changes in fair value | 432 | (e) | 301 | (d) | ||||||||||||||||||||||||||||||||||
Reclassifications from accumulated OCI to net income | Operating Revenues | -608 | (b) | -333 | ||||||||||||||||||||||||||||||||||
Ineffective portion recognized in income | Operating Revenues | 3 | 3 | |||||||||||||||||||||||||||||||||||
Accumulated OCI derivative gain at September 30, 2012 | $ | 752 | (a)(c) | $ | 459 | |||||||||||||||||||||||||||||||||
_____________ | ||||||||||||||||||||||||||||||||||||||
(a) Includes $232 million and $420 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, as of September 30, 2012 and December 31, 2011. | ||||||||||||||||||||||||||||||||||||||
(b) Includes $276 million of losses, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd. | ||||||||||||||||||||||||||||||||||||||
(c) Excludes $22 million of losses and $10 million of losses, net of taxes, related to interest rate swaps and treasury rate locks for the nine months ended September 30, 2012 and year ended December 31, 2011, respectively. | ||||||||||||||||||||||||||||||||||||||
(d) Includes $12 million of losses, net of taxes, related to the effective portion of changes in fair value of interest rate swaps and treasury rate locks. | ||||||||||||||||||||||||||||||||||||||
(e) Includes $88 million of gains, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd through the date of de-designation prior to the merger. | ||||||||||||||||||||||||||||||||||||||
During the three and nine months ended September 30, 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 $84 million and a $543 million pre-tax gain and $283 million and $1,005 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 nine months ended September 30, 2012. | ||||||||||||||||||||||||||||||||||||||
Exelon's former energy-related cash flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $84 million and $324 million pre-tax gain for the three and nine months ended September 30, 2013, respectively, and a $145 million and $548 million pre-tax gain for the three and nine months ended September 30, 2012, respectively. Changes in cash flow hedge ineffectiveness was losses of $5 million for the nine months ended September 30, 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 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, and physical forward sales and purchases but for which the fair value or cash flow hedge elections were not made. For the three and nine months ended September 30, 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 at Exelon and Generation in the Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon's and Generation's Consolidated Statements of Cash Flows. In the tables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized at settlement” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period. | ||||||||||||||||||||||||||||||||||||||
Generation | Intercompany Eliminations | Exelon | ||||||||||||||||||||||||||||||||||||
Purchased | ||||||||||||||||||||||||||||||||||||||
Operating | Power | Operating | ||||||||||||||||||||||||||||||||||||
Three Months Ended September 30, 2013 | Revenues | and Fuel | Total | Revenues (a) | Total | |||||||||||||||||||||||||||||||||
Change in fair value | $ | 175 | $ | 5 | $ | 180 | $ | 0 | $ | 180 | ||||||||||||||||||||||||||||
Reclassification to realized at settlement | 41 | 25 | 66 | 0 | 66 | |||||||||||||||||||||||||||||||||
Net mark-to-market gains | $ | 216 | $ | 30 | $ | 246 | $ | 0 | $ | 246 | ||||||||||||||||||||||||||||
Generation | Intercompany Eliminations | Exelon | ||||||||||||||||||||||||||||||||||||
Purchased | ||||||||||||||||||||||||||||||||||||||
Operating | Power | Operating | ||||||||||||||||||||||||||||||||||||
Nine Months Ended September 30, 2013 | Revenues | and Fuel | Total | Revenues (a) | Total | |||||||||||||||||||||||||||||||||
Change in fair value | $ | 149 | $ | 74 | $ | 223 | $ | -6 | $ | 217 | ||||||||||||||||||||||||||||
Reclassification to realized at settlement | -15 | 63 | 48 | 13 | 61 | |||||||||||||||||||||||||||||||||
Net mark-to-market gains | $ | 134 | $ | 137 | $ | 271 | $ | 7 | $ | 278 | ||||||||||||||||||||||||||||
Generation | Intercompany Eliminations | Exelon | ||||||||||||||||||||||||||||||||||||
Purchased | ||||||||||||||||||||||||||||||||||||||
Operating | Power | Operating | ||||||||||||||||||||||||||||||||||||
Three Months Ended September 30, 2012 | Revenues | and Fuel | Total | Revenues (a) | Total | |||||||||||||||||||||||||||||||||
Change in fair value | $ | -255 | $ | 129 | $ | -126 | $ | 35 | $ | -91 | ||||||||||||||||||||||||||||
Reclassification to realized at settlement | 20 | 122 | 142 | -19 | 123 | |||||||||||||||||||||||||||||||||
Net mark-to-market gains (losses) | $ | -235 | $ | 251 | $ | 16 | $ | 16 | $ | 32 | ||||||||||||||||||||||||||||
Generation | Intercompany Eliminations | Exelon | ||||||||||||||||||||||||||||||||||||
Purchased | ||||||||||||||||||||||||||||||||||||||
Operating | Power | Operating | ||||||||||||||||||||||||||||||||||||
Nine Months Ended September 30, 2012 | Revenues | and Fuel | Total | Revenues (a) | Total | |||||||||||||||||||||||||||||||||
Change in fair value | $ | -85 | $ | 121 | $ | 36 | $ | 62 | $ | 98 | ||||||||||||||||||||||||||||
Reclassification to realized at settlement | -81 | 326 | 245 | -29 | 216 | |||||||||||||||||||||||||||||||||
Net mark-to-market gains (losses) | $ | -166 | $ | 447 | $ | 281 | $ | 33 | $ | 314 | ||||||||||||||||||||||||||||
Prior to the merger, the five-year financial swap contract between Generation and ComEd was de-designated. As a result, all prospective changes in fair value are recorded to operating revenues and eliminated in consolidation. | ||||||||||||||||||||||||||||||||||||||
Proprietary Trading Activities (Exelon and Generation). For the three and nine months ended September 30, 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 derivative instruments entered into for proprietary trading purposes. 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. | ||||||||||||||||||||||||||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||||||||||||||||||||||||
Location on Income | September 30, | September 30, | ||||||||||||||||||||||||||||||||||||
Statement | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||||||||||||||||||||
Change in fair value | Operating Revenue | $ | 0 | $ | -2 | $ | 1 | $ | 12 | |||||||||||||||||||||||||||||
Reclassification to realized at | ||||||||||||||||||||||||||||||||||||||
settlement | Operating Revenue | -40 | 25 | -36 | 57 | |||||||||||||||||||||||||||||||||
Net mark-to-market gains (losses) | Operating Revenue | $ | -40 | $ | 23 | $ | -35 | $ | 69 | |||||||||||||||||||||||||||||
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 September 30, 2013. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. The figures in the tables below do not include credit risk exposure from uranium procurement contracts or exposure through RTOs, ISOs, NYMEX, ICE and Nodal commodity exchanges, further discussed in Item 3. Quantitative and Qualitative Disclosures About Market Risk. Additionally, the figures in the tables below do not include exposures with affiliates, including net receivables with ComEd, PECO and BGE of $33 million, $30 million and $39 million, respectively. | ||||||||||||||||||||||||||||||||||||||
Total | Number of | Net Exposure of | ||||||||||||||||||||||||||||||||||||
Exposure | Counterparties | Counterparties | ||||||||||||||||||||||||||||||||||||
Before Credit | Credit | Net | Greater than 10% | Greater than 10% | ||||||||||||||||||||||||||||||||||
Rating as of September 30, 2013 | Collateral | Collateral | Exposure | of Net Exposure | of Net Exposure | |||||||||||||||||||||||||||||||||
Investment grade | $ | 1,767 | $ | 191 | $ | 1,576 | 1 | $ | 478 | |||||||||||||||||||||||||||||
Non-investment grade | 16 | 9 | 7 | 0 | 0 | |||||||||||||||||||||||||||||||||
No external ratings | ||||||||||||||||||||||||||||||||||||||
Internally rated - investment grade | 472 | 6 | 466 | 1 | 238 | |||||||||||||||||||||||||||||||||
Internally rated - non-investment | ||||||||||||||||||||||||||||||||||||||
grade | 18 | 1 | 17 | 0 | 0 | |||||||||||||||||||||||||||||||||
Total | $ | 2,273 | $ | 207 | $ | 2,066 | 2 | $ | 716 | |||||||||||||||||||||||||||||
Net Credit Exposure by Type of Counterparty | As of September 30, 2013 | |||||||||||||||||||||||||||||||||||||
Investor-owned utilities, marketers and power producers | $ | 743 | ||||||||||||||||||||||||||||||||||||
Energy cooperatives and municipalities | 916 | |||||||||||||||||||||||||||||||||||||
Financial institutions | 355 | |||||||||||||||||||||||||||||||||||||
Other | 52 | |||||||||||||||||||||||||||||||||||||
Total | $ | 2,066 | ||||||||||||||||||||||||||||||||||||
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 September 30, 2013, ComEd's credit exposure to suppliers was immaterial. | ||||||||||||||||||||||||||||||||||||||
ComEd is permitted to recover its costs of procuring energy through the Illinois Settlement Legislation. ComEd's counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 5 – 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. As of September 30, 2013, PECO had no net credit exposure with suppliers. | ||||||||||||||||||||||||||||||||||||||
PECO is permitted to recover its costs of procuring electric supply through its PAPUC-approved DSP Program. PECO's counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 5 - Regulatory Matters for further 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 September 30, 2013, PECO had credit exposure of $9 million under its natural gas supply and asset management agreements with investment grade suppliers. | ||||||||||||||||||||||||||||||||||||||
BGE is permitted to recover its costs of procuring energy through the MDPSC-approved procurement tariffs. BGE's counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 5 - Regulatory Matters for further 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 seller's credit exposure is calculated each business day. As of September 30, 2013, BGE had no net credit exposure to suppliers. | ||||||||||||||||||||||||||||||||||||||
BGE's regulated gas business is exposed to market-price risk. This market-price risk is mitigated by BGE's recovery of its costs to procure natural gas through a gas cost adjustment clause approved by the MDPSC. BGE does make off-system sales after BGE has satisfied its customers' demands, which are not covered by the gas cost adjustment clause. At September 30, 2013, BGE had credit exposure of $1 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: | ||||||||||||||||||||||||||||||||||||||
Credit-Risk Related Contingent Feature | 30-Sep-13 | |||||||||||||||||||||||||||||||||||||
Gross Fair Value of Derivative Contracts Containing this Feature (a) | Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements (b) | Net Fair Value of Derivative Contracts Containing This Feature (c) | ||||||||||||||||||||||||||||||||||||
($961) | $790 | ($171) | ||||||||||||||||||||||||||||||||||||
Credit-Risk Related Contingent Feature | 31-Dec-12 | |||||||||||||||||||||||||||||||||||||
Gross Fair Value of Derivative Contracts Containing this Feature (a) | Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements (b) | Net Fair Value of Derivative Contracts Containing This Feature (c) | ||||||||||||||||||||||||||||||||||||
($1,849) | $1,426 | ($423) | ||||||||||||||||||||||||||||||||||||
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. | ||||||||||||||||||||||||||||||||||||||
Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which a Registrant could potentially be required to post collateral. | ||||||||||||||||||||||||||||||||||||||
Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based. | ||||||||||||||||||||||||||||||||||||||
Generation had cash collateral posted of $353 million and letters of credit posted of $326 million and cash collateral held of $202 million and letters of credit held of $32 million as of September 30, 2013 and cash collateral posted of $527 million and letters of credit posted of $563 million and cash collateral held of $499 million and letters of credit held of $45 million at December 31, 2012 for counterparties with derivative positions. In the event of a credit downgrade below investment grade (i.e., to BB+ or Ba1), Generation could be required to post additional collateral of $1.8 billion as of September 30, 2013 and $2.0 billion as of December 31, 2012. These amounts represent the potential additional collateral required after giving consideration to offsetting derivative and non-derivative positions under master netting agreements. | ||||||||||||||||||||||||||||||||||||||
Generation's and Exelon's interest rate swaps contain provisions that, in the event of a merger, if Generation's debt ratings were to materially weaken, it would be in violation of these provisions, resulting in the ability of the counterparty to terminate the agreement prior to maturity. Collateralization would not be required under any circumstance. Termination of the agreement could result in a settlement payment by Exelon or the counterparty on any interest rate swap in a net liability position. The settlement amount would be equal to the fair value of the swap on the termination date. As of September 30, 2013, Generation's and Exelon's swaps were in an asset position, with a fair value of $19 million and $32 million, respectively. | ||||||||||||||||||||||||||||||||||||||
See Note 21 – Segment Information of the Exelon 2012 Form 10-K for further information regarding the letters of credit supporting the cash collateral. | ||||||||||||||||||||||||||||||||||||||
Generation entered into SFCs 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 September 30, 2013, ComEd held immaterial amounts of collateral from suppliers in association with energy procurement contracts. Under the terms of ComEd's annual renewable energy contracts, collateral postings are required to cover a fixed value for RECs only. In addition, under the terms of ComEd's long-term renewable energy contracts, collateral postings are required from suppliers for both RECs and energy. The REC portion is a fixed value and the energy portion is one-sided from suppliers should the forward market prices exceed contract prices. As of September 30, 2013, ComEd held approximately $19 million in the form of cash and letters of credit as margin for both the annual and long-term REC obligations. See Note 3 – Regulatory Matters of the Exelon 2012 Form 10-K for further 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 September 30, 2013, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of September 30, 2013, PECO could have been required to post approximately $30 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 September 30, 2013, BGE was not required to post collateral for any of these agreements. If BGE lost its investment grade credit rating as of September 30, 2013, BGE could have been required to post approximately $41 million of collateral to its counterparties. |
Debt_and_Credit_Agreements_Exe
Debt and Credit Agreements (Exelon, Generation, ComEd, PECO and BGE) | 9 Months Ended | ||||||||||
Sep. 30, 2013 | |||||||||||
Debt and Credit Agreements [Line Items] | ' | ||||||||||
Debt and Credit Agreements (Exelon, Generation, ComEd, PECO and BGE) | ' | ||||||||||
11. 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. | |||||||||||
The Registrants had the following amounts of commercial paper borrowings outstanding as of September 30, 2013 and December 31, 2012: | |||||||||||
Commercial Paper Borrowings | 30-Sep-13 | 31-Dec-12 | |||||||||
Exelon Corporate | $ | 0 | $ | 0 | |||||||
Generation | 0 | 0 | |||||||||
ComEd | 153 | 0 | |||||||||
PECO | 0 | 0 | |||||||||
BGE | 40 | 0 | |||||||||
Credit Facilities | |||||||||||
Exelon had bank lines of credit under committed credit facilities at September 30, 2013 for short-term financial needs, as follows: | |||||||||||
Type of Credit Facility | Amount (a) | Expiration Dates | Capacity Type | ||||||||
Exelon Corporate | (In billions) | ||||||||||
Syndicated Revolver | $ | 0.5 | Aug-18 | Letters of credit and cash | |||||||
Generation | |||||||||||
Syndicated Revolver | 5.3 | Aug-18 | Letters of credit and cash | ||||||||
Bilateral | 0.3 | December 2015 and March 2016 | Letters of credit and cash | ||||||||
Bilateral | 0.1 | Jan-15 | Letters of credit | ||||||||
ComEd | |||||||||||
Syndicated Revolver | 1 | Mar-18 | Letters of credit and cash | ||||||||
PECO | |||||||||||
Syndicated Revolver | 0.6 | Aug-18 | Letters of credit and cash | ||||||||
BGE | |||||||||||
Syndicated Revolver | 0.6 | Aug-18 | Letters of credit and cash | ||||||||
Total | $ | 8.4 | |||||||||
_____________ | |||||||||||
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 expire on October 18, 2014 and are solely utilized to issue letters of credit. As of September 30, 2013, letters of credit issued under these agreements for Generation, ComEd, PECO and BGE totaled $24 million, $26 million, $21 million and $1 million, respectively. | |||||||||||
As of September 30, 2013, there were no borrowings under the Registrants' credit facilities. | |||||||||||
On January 23, 2013, Generation entered into a two year $75 million bilateral letter of credit facility with a bank. The credit agreement expires in January 2015. This facility will solely be utilized by Generation to issue letters of credit. | |||||||||||
On March 14, 2013, ComEd extended its unsecured revolving credit facility with aggregate bank commitments of $1.0 billion. Under this facility, ComEd may issue letters of credit in the aggregate amount of up to $500 million. The credit agreement expires on March 28, 2018, and ComEd may request another one-year extension of that term. The credit facility also allows ComEd to request increases in the aggregate commitments of up to an additional $500 million. Any such extension or increases are subject to the approval of the lenders party to the credit agreement in their sole discretion. Costs incurred to extend the facility for ComEd were not material. | |||||||||||
On August 10, 2013, Exelon Corporate, Generation, PECO and BGE amended and extended their respective unsecured syndicated revolving credit facilities, with aggregate bank commitments of $500 million, $5.3 billion, $600 million and $600 million, respectively. The new covenants are substantially consistent with existing covenants. Costs incurred to amend and extend the facilities for Exelon Corporate, Generation, PECO and BGE were not material. | |||||||||||
Effective August 10, 2013, Exelon and ComEd entered into amendments to each of their respective revolving credit facilities (the Amendments). The Amendments relate to the IRS's challenge to the position taken by Exelon on its 1999 federal income tax return with respect to the sale of ComEd's fossil generating assets in a like-kind exchange tax position. The Amendments are intended to exclude the non-cash impact of the like-kind exchange tax position from the calculation of the interest coverage ratio under each of Exelon and ComEd's respective credit facilities. See Note 12 – Income Taxes for additional information. | |||||||||||
Borrowings under Exelon Corporate's, Generation's, ComEd's, PECO's and BGE's credit agreements bear interest at a rate based upon either the prime rate or a LIBOR-based rate, plus an adder based upon the particular registrant's credit rating. Exelon Corporate, Generation, ComEd, PECO and BGE have adders of 27.5, 27.5, 27.5, 0.0 and 7.5 basis points for prime based borrowings and 127.5, 127.5, 127.5, 100.0 and 107.5 basis points for LIBOR-based borrowings. The maximum adders for prime rate borrowings and LIBOR-based rate borrowings are 65 basis points and 165 basis points, respectively. The credit agreements also require the borrower to pay a facility fee based upon the aggregate commitments under the agreement. The fee varies depending upon the respective credit ratings of the borrower. | |||||||||||
On October 18, 2013, Generation, ComEd, PECO and BGE replaced their respective minority and community bank credit facility agreements in the amounts of $50 million, $34 million, $34 million and $5 million, respectively. These facilities, which expire in October 2014, are solely utilized to issue letters of credit. | |||||||||||
Long-Term Debt | |||||||||||
Issuance of Long-Term Debt | |||||||||||
During the nine months ended September 30, 2013, the following long-term debt was issued: | |||||||||||
Company | Type | Interest Rate | Maturity | Amount | Use of Proceeds | ||||||
Generation | Upstream Gas Lending Agreement | 2.210 - 2.440 | % | 22-Jul-16 | $ | 5 | Used to fund Upstream gas activities | ||||
Generation | DOE Project Financing | 2.535 - 3.353 | % | 5-Jan-37 | $ | 204 | Funding for Antelope Valley Solar Development | ||||
Generation | Energy Efficiency Project Financing | 4.4 | % | 31-Aug-14 | $ | 9 | Funding to install energy conservation measures in Beckley, West Virginia | ||||
Generation | Continental Wind Senior Secured Notes | 6 | % | 28-Feb-33 | $ | 613 | Used for general corporate purposes | ||||
ComEd | First Mortgage Bonds | 4.6 | % | 15-Aug-43 | $ | 350 | Used to repay outstanding commercial paper obligations and for general corporate purposes | ||||
PECO | First and Refunding Mortgage Bonds | 1.2 | % | 15-Oct-16 | $ | 300 | Used to pay at maturity first and refunding mortgage bonds due October 15, 2013 and other general corporate purposes | ||||
PECO | First and Refunding Mortgage Bonds | 4.8 | % | 15-Oct-43 | $ | 250 | Used to pay at maturity first and refunding mortgage bonds due October 15, 2013 and other general corporate purposes | ||||
BGE | Senior Notes | 3.35 | % | 1-Jul-23 | $ | 300 | Used to partially refinance Notes due July 1, 2013 and for general corporate purposes | ||||
During the nine months ended September 30, 2012, the following long-term debt was issued: | |||||||||||
Company | Type | Interest Rate | Maturity | Amount | Use of Proceeds | ||||||
Generation | Senior Notes | 4.25 | % | 15-Jun-22 | $ | 523 | Used for general corporate purposes and issued in connection with the Exchange Offer | ||||
Generation | Senior Notes | 5.6 | % | 15-Jun-42 | $ | 788 | Used for general corporate purposes and issued in connection with the Exchange Offer | ||||
Generation | CEU Credit Agreement | 1.99 | % | 16-Jun-16 | $ | 43 | Used to fund upstream gas activities | ||||
Generation | DOE Project Financing | 2.330 - 3.092 | % | 5-Jan-37 | $ | 100 | Funding for Antelope Valley Solar Development | ||||
Generation | Clean Horizons | 2.5 | % | 7-Jun-30 | $ | 38 | Funding for Maryland solar development | ||||
PECO | First and Refunding Mortgage Bonds | 2.375 | % | 15-Sep-22 | $ | 350 | Used to pay at maturity First Mortgage Bonds due October 1, 2012 and for general corporate purposes | ||||
BGE | Notes | 2.8 | % | 15-Aug-32 | $ | 250 | Used to repay total outstanding commercial paper and for general corporate purposes | ||||
Retirement of Current and Long-Term Debt | |||||||||||
During the nine months ended September 30, 2013, the following long-term debt was retired: | |||||||||||
Company | Type | Interest Rate | Maturity | Amount | |||||||
Generation | Kennett Square Capital Lease | 7.83 | % | 20-Sep-20 | $ | 2 | |||||
Generation | Solar Revolver | 1.930 - 1.950 | % | 7-Jul-14 | $ | 18 | |||||
Generation | Clean Horizons | 2.563 | % | 7-Sep-30 | $ | 1 | |||||
Generation (a) | Series A Junior Subordinated Debentures | 8.625 | % | 15-Jun-63 | $ | 450 | |||||
ComEd | First Mortgage Bonds Series 92 | 7.625 | % | 15-Apr-13 | $ | 125 | |||||
ComEd | First Mortgage Bonds Series 94 | 7.5 | % | 1-Jul-13 | $ | 127 | |||||
BGE | Senior Notes | 6.125 | % | 1-Jul-13 | $ | 400 | |||||
BGE | Rate Stabilization Bonds | 5.72 | % | 1-Apr-17 | $ | 33 | |||||
_______________ | |||||||||||
Represents debt obligations assumed by Exelon as part of the merger on March 12, 2012 that became callable at face value on June 15, 2013. 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 as of December 31, 2012 included in long-term debt to affiliate on Generation's Consolidated Balance Sheets and notes receivable from affiliates at Exelon Corporate, which are eliminated in consolidation on Exelon's Consolidated Balance Sheets. The third-party debt obligations were reported in Long-term Debt on Exelon's Consolidated Balance Sheets as of December 31, 2012. The debentures were redeemed and the intercompany loan agreements repaid on June 15, 2013. | |||||||||||
On October 1, 2013, BGE retired $34 million aggregate principal of its 5.720% Rate Stabilization Bonds due April 1, 2017. | |||||||||||
On October 15, 2013, PECO retired $300 million aggregate principal of its 5.600% First and Refunding Mortgage Bonds due October 15, 2013. | |||||||||||
During the nine months ended September 30, 2012, the following long-term debt was retired: | |||||||||||
Company | Type | Interest Rate | Maturity | Amount | |||||||
ComEd | First Mortgage Bond Series 98 | 6.15 | % | 15-Mar-12 | $ | 450 | |||||
BGE | Rate Stabilization Bonds | 5.68 | % | 1-Apr-17 | $ | 31 | |||||
BGE | Medium Term Notes | 6.73 - 6.75 | % | 15-Jun-12 | $ | 110 | |||||
Generation | Kennett Square Capital Lease | 7.83 | % | 20-Sep-20 | $ | 2 | |||||
Generation | Armstrong Co. tax-exempt | 5 | % | 1-Dec-42 | $ | 46 | |||||
Generation | MEDCO Tax-Exempt Bonds | Various | 1-Apr-24 | $ | 75 | ||||||
Generation | Solar Revolver | 2.49 | % | 7-Jul-14 | $ | 13 | |||||
Generation | CEU Credit Agreement | 2.27 | % | 16-Jul-16 | $ | 3 | |||||
Exelon | Senior Notes | 7.6 | % | 1-Apr-32 | $ | 442 | |||||
Exelon | Medium Term Notes | 7.3 | % | 1-Jun-12 | $ | 2 | |||||
Accounts Receivable Agreement | |||||||||||
PECO was party to an agreement with a financial institution under which it transferred an undivided interest, adjusted daily, in its accounts receivable designated under the agreement in exchange for proceeds of $210 million, which was classified as a short-term note payable on Exelon's and PECO's Consolidated Balance Sheets as of December 31, 2012. The agreement terminated on August 30, 2013 and PECO paid down the outstanding principal of $210 million. The financial institution no longer has an undivided interest in the accounts receivable designated under the agreement. As of December 31, 2012, the financial institution's undivided interest in Exelon's and PECO's gross accounts receivable was equivalent to $289 million, which represented the financial institution's interest in PECO's eligible receivables as calculated under the terms of the agreement. The agreement required PECO to maintain eligible receivables at least equivalent to the financial institution's undivided interest. | |||||||||||
Willis Tower Capital Lease | |||||||||||
In the second quarter of 2013, ComEd entered into a 20-year capital lease for transmission distribution space at Willis Tower in Chicago, Illinois. ComEd recorded $8 million on its Consolidated Balance Sheets within property plant and equipment and long-term debt at the inception of the lease. ComEd will make lease payments of less than $1 million annually in 2013-2017 and approximately $7 million thereafter. | |||||||||||
Non-Recourse Debt | |||||||||||
The following are descriptions of activity that occurred for the nine months ended September 30, 2013 of certain indebtedness of Exelon's project subsidiaries. The indebtedness described below is specific to certain generating facilities pledged as collateral with a net book value of approximately $1.8 billion at September 30, 2013, and all associated project financing liabilities are non-recourse to Exelon and Generation. | |||||||||||
Continental Wind | |||||||||||
On September 30, 2013, Continental Wind, LLC (Continental Wind), an indirect subsidiary of Exelon and Generation, completed the issuance and sale of $613 million aggregate principal amount of Continental Wind's 6.00% senior secured notes due February 28, 2033. Continental Wind owns and operates a portfolio of wind farms in Idaho, Kansas, Michigan, Oregon, New Mexico and Texas with a total net capacity of 667 MW. The net proceeds were distributed to Generation for its general business purposes. In connection with this non-recourse project financing, Exelon terminated existing interest rate swaps with a total notional amount of $350 million during the third quarter of 2013, and realized a total gain of $26 million upon termination. The gain on the interest rate swaps was recorded within OCI and will reduce the effective interest rate over the life of the debt for Exelon. See Note 10 – 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 the credit support and security obligations of itself. As of September 30, 2013, the Continental Wind letter of credit facility had $90 million in letters of credit outstanding related to the project. | |||||||||||
Antelope Valley Project Development Debt Agreement | |||||||||||
The DOE Loan Programs Office issued a guarantee for up to $646 million for a non-recourse loan from the Federal Financing Bank to support the financing of the construction of the Antelope Valley facility. The project is expected to be completed the first half of 2014. | |||||||||||
In addition, Generation has issued letters of credit to support its equity investment in the project. As of September 30, 2013, Generation has reduced the letters of credit outstanding related to the project to $327 million. The letters of credit balance is expected to decline over time as scheduled equity contributions for the project are made. | |||||||||||
Income_Taxes_Exelon_Generation
Income Taxes (Exelon, Generation, ComEd, PECO and BGE) | 9 Months Ended | |||||||||||||||
Sep. 30, 2013 | ||||||||||||||||
Income Taxes [Line Items] | ' | |||||||||||||||
Income Taxes (Exelon, Generation, ComEd, PECO and BGE) | ' | |||||||||||||||
12. Income Taxes (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||
The effective income tax rate from continuing operations varies from the U.S. Federal statutory rate principally due to the following: | ||||||||||||||||
For the Three Months Ended September 30, 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 | 3 | 2.6 | 5.4 | -0.3 | 5.6 | |||||||||||
Qualified nuclear decommissioning trust fund income | 3.5 | 5.3 | 0 | 0 | 0 | |||||||||||
Tax exempt income | -0.2 | -0.3 | 0 | 0 | 0 | |||||||||||
Health care reform legislation | 0.1 | 0 | 0.4 | 0 | 0.2 | |||||||||||
Amortization of investment tax credit, net deferred taxes | -1.5 | -2.1 | -0.4 | -0.1 | -0.3 | |||||||||||
Plant basis differences | -0.8 | 0 | -0.4 | -6.9 | 0.1 | |||||||||||
Production tax credits and other credits | -2.2 | -3.3 | 0 | 0 | 0 | |||||||||||
Other | 0.5 | 0.1 | 0.3 | -0.1 | -0.2 | |||||||||||
Effective income tax rate | 37.4 | % | 37.3 | % | 40.3 | % | 27.6 | % | 40.4 | % | ||||||
For the Nine Months Ended September 30, 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 | 5.3 | 1.8 | 5.2 | 1.9 | 5.6 | |||||||||||
Qualified nuclear decommissioning trust fund income | 3.2 | 5.1 | 0 | 0 | 0 | |||||||||||
Tax exempt income | -0.2 | -0.3 | 0 | 0 | 0 | |||||||||||
Health care reform legislation | 0.1 | 0 | 0.9 | 0 | 0.2 | |||||||||||
Amortization of investment tax credit, net deferred taxes | -2.3 | -3.4 | -0.8 | -0.1 | -0.3 | |||||||||||
Plant basis differences | -1.7 | 0 | -1.2 | -7.3 | -0.4 | |||||||||||
Production tax credits and other credits | -2.4 | -3.9 | 0 | 0 | 0 | |||||||||||
Other | 0.2 | 1.1 | 0.8 | 0 | 0 | |||||||||||
Effective income tax rate | 37.2 | % | 35.4 | % | 39.9 | % | 29.5 | % | 40.1 | % | ||||||
For the Three Months Ended September 30, 2012 | Exelon(a) | Generation(a) | ComEd | PECO | BGE (b) | |||||||||||
U.S. Federal statutory rate | 35 | % | 35 | % | 35 | % | 35 | % | 0 | % | ||||||
Increase (decrease) due to: | ||||||||||||||||
State income taxes, net of Federal income tax benefit | 5.6 | 5.9 | 5 | 3 | 0 | |||||||||||
Qualified nuclear decommissioning trust fund income | 7.8 | 21.5 | 0 | 0 | 0 | |||||||||||
Domestic production activities deduction | 0.3 | 0.8 | 0 | 0 | 0 | |||||||||||
Tax exempt income | -0.2 | -0.5 | 0 | 0 | 0 | |||||||||||
Health care reform legislation | 0 | 0 | 0.6 | 0 | 0 | |||||||||||
Amortization of investment tax credit, net deferred taxes | -4.8 | -13 | -0.5 | -0.3 | 0 | |||||||||||
Plant basis differences | -4.7 | 0 | -0.5 | -21 | 0 | |||||||||||
Production tax credits and other credits | -2.5 | -7.4 | 0 | 0 | 0 | |||||||||||
Fines and Penalties | -0.1 | 0 | 0 | 0 | 0 | |||||||||||
Other (d) | -1.2 | 7.1 | 0 | 0.2 | 0 | |||||||||||
Effective income tax rate | 35.2 | % | 49.4 | % | 39.6 | % | 16.9 | % | 0 | % | ||||||
For the Nine Months Ended September 30, 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 | -4.7 | 2.5 | 5.4 | 3.2 | 2.3 | |||||||||||
Qualified nuclear decommissioning trust fund income | 6.9 | 10.9 | 0 | 0 | 0 | |||||||||||
Tax exempt income | -0.3 | -0.5 | 0 | 0 | 0 | |||||||||||
Health care reform legislation | 0.2 | 0 | 0.6 | 0 | -4.6 | |||||||||||
Amortization of investment tax credit, net deferred taxes | -2.3 | -3.3 | -0.5 | -0.3 | 2.9 | |||||||||||
Plant basis differences | -2.2 | 0 | -0.2 | -9.7 | 7.2 | |||||||||||
Production tax credits and other credits | -2.6 | -4.3 | 0 | 0 | 0 | |||||||||||
Fines and Penalties | 3.8 | 6 | 0 | 0 | 0 | |||||||||||
Merger expenses (c) | 3.6 | 0 | 0 | 0 | -14 | |||||||||||
Other | -1.3 | 0.8 | 0.2 | 0 | 4.5 | |||||||||||
Effective income tax rate | 36.1 | % | 47.1 | % | 40.5 | % | 28.2 | % | 33.3 | % | ||||||
(a) Exelon activity for the three and nine months ended September 30, 2012 includes the results of Constellation and BGE for March 12, 2012 - September 30, 2012. Generation activity for the three and nine months ended September 30, 2012 includes the results of Constellation for March 12, 2012 - September 30, 2012. | ||||||||||||||||
(b) BGE activity represents the activity for the three and nine months ended September 30, 2012. BGE activity for the three months ended September 30, 2012 resulted in zero pre-tax income and zero income taxes. BGE recognized a loss before income taxes for the nine months ended September 30, 2012. As a result, positive percentages represent an income tax benefit for BGE for the nine months ended September 30, 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. | ||||||||||||||||
(d) For the three months ended September 30, 2012, Generation's effective tax rate was affected by the resolution of uncertain Federal tax positions (5.3%), the finalization of prior year tax return calculations 4.2%, changes in the forecasted activity attributable to noncontrolling interests 4.1%, and other 4.1%. | ||||||||||||||||
Accounting for Uncertainty in Income Taxes | ||||||||||||||||
Exelon, Generation, ComEd, PECO, and BGE have $2,164 million, $1,406 million, $327 million, $44 million, and $0 million, of unrecognized tax benefits as of September 30, 2013, respectively, and $1,024 million, $876 million, $67 million, $44 million, and $0 million, of unrecognized tax benefits as of December 31, 2012, respectively. The unrecognized tax benefits as of September 30, 2013 reflect an increase at Exelon and ComEd attributable to the like-kind exchange position discussed below. Furthermore, Exelon's and Generation's unrecognized tax benefits were increased by $446 million in the second quarter in anticipation of filing a refund claim with respect to legacy Constellation taxable years. | ||||||||||||||||
Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date | ||||||||||||||||
Settlement of Income Tax Audits | ||||||||||||||||
As of September 30, 2013, Exelon and Generation have approximately $160 million of federal and state unrecognized tax benefits that could significantly increase or decrease within the 12 months after the reporting date as a result of completing federal and state audits and expected statute of limitation expirations that if recognized would decrease the effective tax rate. | ||||||||||||||||
Nuclear Decommissioning Liabilities (Exelon and Generation) | ||||||||||||||||
AmerGen filed income tax refund claims taking the position that nuclear decommissioning liabilities assumed as part of its acquisition of nuclear power plants are taken into account in determining the tax basis in the assets it acquired. The additional basis results primarily in reduced capital gains or increased capital losses on the sale of assets in nonqualified decommissioning funds and increased tax depreciation and amortization deductions. The IRS disagrees with this position and has disallowed the claims. In November 2008, Generation received a final determination from the Appeals division of the IRS (IRS Appeals) disallowing AmerGen's refund claims. Generation filed a complaint in the United States Court of Federal Claims on February 20, 2009 to contest this determination. During the first and second quarters of 2013, AmerGen and the DOJ completed and filed cross motions for summary judgment. On September 17, 2013, the Court granted the government's motion denying AmerGen's claims for refund. Exelon is currently considering an appeal of the decision to the United States Court of Appeals for the Federal Circuit. | ||||||||||||||||
Due to the possibility of final resolution through an appellate decision, Generation continues to believe that it is reasonably possible that the total amount of unrecognized tax benefits may significantly decrease in the next twelve months. | ||||||||||||||||
Other Income Tax Matters | ||||||||||||||||
Involuntary Conversion, Like-Kind Exchange and Competitive Transition Charges | ||||||||||||||||
1999 Sale of Fossil Generating Assets (Exelon and ComEd). Exelon, through its ComEd subsidiary, took two positions on its 1999 income tax return to defer approximately $2.8 billion of tax gain on the sale of ComEd's fossil generating assets. Exelon deferred approximately $1.6 billion of the gain under the involuntary conversion provisions of the IRC. Exelon believed that it was economically compelled to dispose of ComEd's fossil generating plants as a result of the Illinois Act and that the proceeds from the sale of the fossil plants were properly reinvested in qualifying replacement property such that the gain could be deferred over the lives of the replacement property under the involuntary conversion provisions. The remaining approximately $1.2 billion of the gain was deferred by reinvesting the proceeds from the sale in qualifying replacement property under the like-kind exchange provisions of the IRC. The like-kind exchange replacement property purchased by Exelon included interests in three municipal-owned electric generation facilities which were properly leased back to the municipalities. The IRS disagreed with both positions and asserted that the entire gain of approximately $2.8 billion was taxable in 1999. | ||||||||||||||||
Competitive Transition Charges (Exelon, ComEd, and PECO). Exelon contended that the Illinois Act and the Competition Act resulted in the taking of certain of ComEd's and PECO's assets used in their respective businesses of providing electricity services in their defined service areas. Exelon filed refund claims with the IRS taking the position that CTCs collected during ComEd's and PECO's transition periods represent compensation for that taking and, accordingly, were excludible from taxable income as proceeds from an involuntary conversion. The tax basis of property acquired with the funds provided by the CTCs would be reduced such that the benefits of the position are temporary in nature. The IRS disallowed the refund claims for the 1999-2001 tax years. | ||||||||||||||||
Status of Involuntary Conversion and CTC Positions. In the second quarter of 2010, the IRS offered to settle the disagreement over the involuntary conversion and CTC positions. Exelon concluded, based on that offer, that it had sufficient new information that a remeasurement of the involuntary conversion and CTC positions was required in accordance with applicable accounting standards. As a result of the required remeasurement, Exelon recorded $65 million (after-tax) of interest expense, of which $36 million (after-tax) and $22 million (after-tax) were recorded at ComEd and PECO, respectively. ComEd also recorded a current tax expense of $70 million offset with a tax benefit recorded at Generation of $70 million. In the third quarter of 2010, Exelon and the IRS reached a nonbinding, preliminary agreement to settle Exelon's involuntary conversion on terms consistent with the settlement offer received in the second quarter. As a result of the preliminary agreement, Exelon and ComEd eliminated any liability for unrecognized tax benefits and established a current tax payable to the IRS. Exelon paid $302 million in late 2010 in advance of the final settlement and the assessment. In November 2012, the IRS and Exelon finalized and executed definitive agreements to resolve Exelon's involuntary conversion and CTC positions. | ||||||||||||||||
Status of Like-Kind Exchange Position. Exelon has been unable to reach agreement with the IRS regarding the dispute over the like kind exchange position. The IRS has asserted that the Exelon purchase and leaseback transaction is substantially similar to a leasing transaction, known as a SILO, which the IRS does not respect as the acquisition of an ownership interest in property. A SILO is a “listed transaction” that the IRS has identified as a potentially abusive tax shelter under guidance issued in 2005. Accordingly, the IRS has asserted that the sale of the fossil plants followed by the purchase and leaseback of the municipal owned generation facilities does not qualify as a like-kind exchange and the gain on the sale is fully subject to tax. The IRS has also asserted a penalty of approximately $87 million for a substantial understatement of tax. | ||||||||||||||||
Exelon disagrees with the IRS and continues to believe that its like-kind exchange transaction is not the same as or substantially similar to a SILO. Although Exelon has been and remains willing to settle the disagreement on terms commensurate with the hazards of litigation, Exelon does not believe a settlement is possible. Because Exelon believed, as of December 31, 2012, that it was more-likely-than-not that Exelon would prevail in litigation, Exelon and ComEd had no liability for unrecognized tax benefits with respect to the like kind exchange position. | ||||||||||||||||
On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit reversed the U.S. Court of Federal Claims and reached a decision for the government in Consolidated Edison v. United States. The Court disallowed Consolidated Edison's deductions stemming from its participation in a LILO transaction that the IRS also has characterized as a tax shelter. | ||||||||||||||||
In accordance with applicable accounting standards, Exelon is required to assess whether it is more-likely-than-not that it will prevail in litigation. Exelon continues to believe that its transaction is not a SILO and that it has a strong case on the merits. However, in light of the Consolidated Edison decision and Exelon's current determination that settlement is unlikely, Exelon has concluded that subsequent to December 31, 2012, it is no longer more-likely-than-not that its position will be sustained. As a result, in the first quarter of 2013 Exelon recorded a non-cash charge to earnings of approximately $265 million, which represents the amount of interest expense (after-tax) and incremental state income tax expense for periods through March 31, 2013 that would be payable in the event that Exelon is unsuccessful in litigation. Of this amount, approximately $170 million was recorded at ComEd. Exelon intends to hold ComEd harmless from any unfavorable impacts of the after-tax interest amounts on ComEd's equity. As such, ComEd recorded on its consolidated balance sheet as of March 31, 2013, a $172 million receivable and non-cash equity contributions from Exelon. Exelon and ComEd will continue to accrue interest on the uncertain tax position, and the charges arising from future interest accruals are not expected to be material to the annual operating earnings of Exelon or ComEd. In addition, ComEd will continue to record a receivable and non-cash equity contribution from Exelon in amounts equal to the additional interest recorded by ComEd on the uncertain tax position. Exelon continues to believe that it is unlikely that the $87 million penalty assertion will ultimately be sustained and therefore no liability for the penalty has been recorded. | ||||||||||||||||
On September 30, 2013, the Internal Revenue Service issued a notice of deficiency to Exelon for the like-kind exchange position. Exelon will initiate litigation by December 29, 2013 in the United States Tax Court and is not required to remit any part of the asserted tax or penalty in order to litigate the issue. The litigation could take three to five years including appeals, if necessary. Decisions in the Tax Court are not controlled by the Federal Circuit's decision in Consolidated Edison. | ||||||||||||||||
As of September 30, 2013, in the event of a fully successful IRS challenge to Exelon's like-kind exchange position, the potential tax and after-tax interest, exclusive of penalties, that could become currently payable may be as much as $840 million, of which approximately $305 million would be attributable to ComEd after consideration of Exelon's agreement to hold ComEd harmless, and the balance at Exelon. Litigation could take several years such that the estimated cash and interest impacts would likely change by a material amount. | ||||||||||||||||
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 are currently assessing 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. | ||||||||||||||||
Accounting for Generation Repairs (Exelon and Generation) | ||||||||||||||||
On April 30, 2013, the IRS issued guidance that will facilitate the determination of the appropriate tax treatment of costs incurred to repair electric generation assets. Exelon and Generation are currently assessing its impact and expect to file a request for change in method of tax accounting for repair costs beginning with its 2014 taxable year. |
Asset_Retirement_Obligations_E
Asset Retirement Obligations (Exelon, Generation, ComEd and PECO) | 9 Months Ended | ||||||||||||
Sep. 30, 2013 | |||||||||||||
Asset Retirement Obligations [Line Items] | ' | ||||||||||||
Asset Retirement Obligations (Exelon, Generation, ComEd and PECO) | ' | ||||||||||||
13. Nuclear Decommissioning (Exelon and Generation) | |||||||||||||
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 December 31, 2012 to September 30, 2013: | |||||||||||||
Nuclear decommissioning ARO at December 31, 2012 (a) | $ | 4,741 | |||||||||||
Accretion expense | 194 | ||||||||||||
Net decrease due to changes in, and timing of, estimated cash flows | -141 | ||||||||||||
Costs incurred to decommission retired plants | -2 | ||||||||||||
Nuclear decommissioning ARO at September 30, 2013 (a) | $ | 4,792 | |||||||||||
(a) Includes $10 million as the current portion of the ARO at September 30, 2013 and December 31, 2012, respectively, which is included in Other current liabilities on Exelon's and Generation's Consolidated Balance Sheets. | |||||||||||||
During the nine months ended September 30, 2013, Generation's ARO increased by approximately $51 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 CARFRs, which have increased from the prior year. The decrease in the ARO due to the changes in, and timing of, estimated cash flows were entirely offset by decreases in Property, plant and equipment within Exelon's and Generation's Consolidated Balance Sheets. | |||||||||||||
During the nine months ended September 30, 2012, Generation's ARO increased by $916 million. The increase in the ARO was largely driven by four factors: i) changes in the timing of the future nominal cash flows resulting from an assumed five year deferral to 2025 of the acceptance date of spent nuclear fuel by the DOE coupled with the fact that; ii) cash flows affected by this change in timing are re-measured and discounted at current CARFRs, which had dramatically decreased given the lower interest rate environment; iii) an increase in the estimated costs to decommission the Quad Cities and Dresden nuclear units resulting from the completion of updated decommissioning costs studies received during 2012; and iv) accretion of the obligation. The increase in the ARO due to the changes in, and timing of, estimated cash flows resulted in $10 million of expense, which is included in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. | |||||||||||||
Nuclear Decommissioning Trust Fund Investments | |||||||||||||
NDT funds have been established for each generating station unit to satisfy Generation's nuclear decommissioning obligations. Generally, NDT funds established for a particular unit may not be used to fund the decommissioning obligations of another unit. | |||||||||||||
The NDT funds associated with the former ComEd, former PECO and former AmerGen units have been funded with amounts collected from ComEd customers, PECO customers and the previous owners of the former AmerGen plants, respectively. Based on an ICC order, ComEd ceased collecting amounts from its customers to pay for decommissioning costs. PECO is authorized to collect funds, in revenues, for decommissioning the former PECO nuclear plants through regulated rates, and these collections are scheduled through the operating lives of the plants. The amounts collected from PECO customers are remitted to Generation and deposited into the NDT funds for the unit for which funds are collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO's calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. The most recent rate adjustment occurred on January 1, 2013, and the effective rates currently yield annual collections of approximately $24 million. The next five-year adjustment is expected to be reflected in rates charged to PECO customers effective January 1, 2018. With respect to the former AmerGen units, Generation does not collect any amounts, nor is there any mechanism by which Generation can seek to collect additional amounts, from customers. Apart from the contributions made to the NDT funds from amounts collected from ComEd and PECO customers, Generation has not made contributions to the NDT funds. | |||||||||||||
Any shortfall of funds necessary for decommissioning, determined for each generating station unit, is ultimately required to be funded by Generation, with the exception of a shortfall for the current decommissioning activities at Zion Station, where certain decommissioning activities have been transferred to a third party (see Zion Station Decommissioning below). Generation has recourse to collect additional amounts from PECO customers related to a shortfall of NDT funds for the former PECO units, subject to certain limitations and thresholds, as prescribed by an order from the PAPUC. Generally, PECO will not be allowed to collect amounts associated with the first $50 million of any shortfall of trust funds, on an aggregate basis for all former PECO units, compared to decommissioning obligations, as well as 5% of any additional shortfalls. The initial $50 million and up to 5% of any additional shortfalls would be borne by Generation. No recourse exists to collect additional amounts from ComEd customers for the former ComEd units or from the previous owners of the former AmerGen units. With respect to the former ComEd and PECO units, any funds remaining in the NDTs after all decommissioning has been completed are required to be refunded to ComEd's or PECO's customers, subject to certain limitations that allow sharing of excess funds with Generation related to the former PECO units. With respect to the former AmerGen units, Generation retains any funds remaining in the funds after decommissioning. | |||||||||||||
At September 30, 2013 and December 31, 2012, Exelon and Generation had NDT fund investments totaling $7,776 million and $7,248 million, respectively. The following table provides unrealized gains (losses) on NDT funds for the three and nine months ended September 30, 2013 and 2012: | |||||||||||||
Exelon and Generation | |||||||||||||
Three Months Ended | Nine Months Ended | ||||||||||||
September 30, | September 30, | ||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||
Net unrealized gains on decommissioning trust funds — | |||||||||||||
Regulatory Agreement Units (a) | $ | 103 | $ | 202 | $ | 196 | $ | 352 | |||||
Net unrealized gains on decommissioning trust funds — | |||||||||||||
Non-Regulatory Agreement Units (b)(c) | 46 | 71 | 70 | 101 | |||||||||
Exelon and Generation | |||||||||||||
September 30, | December 31, | ||||||||||||
2013 | 2012 | ||||||||||||
Carrying value of Zion Station pledged assets | $ | 486 | $ | 614 | |||||||||
Payable to Zion Solutions (a) | 443 | 564 | |||||||||||
Current portion of payable to Zion Solutions (b) | 104 | 132 | |||||||||||
Withdrawals by Zion Solutions to pay decommissioning costs (c) | 458 | 335 | |||||||||||
__________ | |||||||||||||
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. | |||||||||||||
Included in Other current liabilities within Exelon's and Generation's Consolidated Balance Sheets. | |||||||||||||
Cumulative withdrawals since September 1, 2010. | |||||||||||||
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. On April 1, 2013, Generation submitted its NRC-required biennial decommissioning funding status report as of December 31, 2012. As of December 31, 2012, Generation provided adequate funding assurance for all of its units, including Limerick Unit 1, where Generation has in place a $115 million parent guarantee to cover the NRC minimum funding assurance requirements. On October 2, 2013, the NRC issued summary findings from the NRC Staff's review of the 2013 decommissioning funding status reports for all 104 operating reactors, including the Generation operating units. Based on that review, the NRC Staff determined that Generation provided decommissioning funding assurance under the NRC regulations for all of its operating units, including Limerick Unit 1. | |||||||||||||
On January 31, 2013, Generation received a letter from the NRC indicating that the NRC has identified potential “apparent violations” of its regulations because of alleged inaccuracies in the Decommissioning Funding Status reports for 2005, 2006, 2007, and 2009. The NRC asserted that Generation's status reports deliberately reflected cost estimates for decommissioning its nuclear plants that were less than what the NRC says are the minimum amounts required by NRC regulations. Generation met with the NRC on April 30, 2013 for a pre-decisional enforcement conference to provide additional information to explain why Generation believes that it complied with the regulatory requirements and did not deliberately or otherwise provide incomplete or inaccurate information in its decommissioning funding status reports. While Generation does not believe that any sanction is appropriate, the ultimate outcome of this proceeding including the amount of a potential fine or sanction, if any, is uncertain. The January 31, 2013 letter from the NRC does not take issue with Generation's current funding status, and as reflected in Generation's April 1, 2013 decommissioning funding status report referenced above, Generation continues to provide adequate funding assurance for each of its units. In the normal course of NRC review, Generation has received a series of data requests that are unrelated to the potential apparent violations and the pre-decisional enforcement conference. Generation continues to cooperate with the NRC and provide the requested information. Generation does not have a definite date on which it will receive a response from the NRC. Although the government shutdown may delay receipt of a response from the NRC, Generation anticipates that the NRC will issue its findings this year. | |||||||||||||
In addition, on June 24, 2013, Exelon received a subpoena from the SEC requesting that Exelon provide the SEC with certain documents generally relating to Exelon and Generation's reporting and funding of the future decommissioning of Exelon's nuclear power plants. Exelon and Generation are cooperating with the SEC and providing the requested documents. | |||||||||||||
Exelon Generation Co L L C [Member] | ' | ||||||||||||
Asset Retirement Obligations [Line Items] | ' | ||||||||||||
Asset Retirement Obligations (Exelon, Generation, ComEd and PECO) | ' | ||||||||||||
13. Nuclear Decommissioning (Exelon and Generation) | |||||||||||||
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 December 31, 2012 to September 30, 2013: | |||||||||||||
Nuclear decommissioning ARO at December 31, 2012 (a) | $ | 4,741 | |||||||||||
Accretion expense | 194 | ||||||||||||
Net decrease due to changes in, and timing of, estimated cash flows | -141 | ||||||||||||
Costs incurred to decommission retired plants | -2 | ||||||||||||
Nuclear decommissioning ARO at September 30, 2013 (a) | $ | 4,792 | |||||||||||
(a) Includes $10 million as the current portion of the ARO at September 30, 2013 and December 31, 2012, respectively, which is included in Other current liabilities on Exelon's and Generation's Consolidated Balance Sheets. | |||||||||||||
During the nine months ended September 30, 2013, Generation's ARO increased by approximately $51 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 CARFRs, which have increased from the prior year. The decrease in the ARO due to the changes in, and timing of, estimated cash flows were entirely offset by decreases in Property, plant and equipment within Exelon's and Generation's Consolidated Balance Sheets. | |||||||||||||
During the nine months ended September 30, 2012, Generation's ARO increased by $916 million. The increase in the ARO was largely driven by four factors: i) changes in the timing of the future nominal cash flows resulting from an assumed five year deferral to 2025 of the acceptance date of spent nuclear fuel by the DOE coupled with the fact that; ii) cash flows affected by this change in timing are re-measured and discounted at current CARFRs, which had dramatically decreased given the lower interest rate environment; iii) an increase in the estimated costs to decommission the Quad Cities and Dresden nuclear units resulting from the completion of updated decommissioning costs studies received during 2012; and iv) accretion of the obligation. The increase in the ARO due to the changes in, and timing of, estimated cash flows resulted in $10 million of expense, which is included in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. | |||||||||||||
Nuclear Decommissioning Trust Fund Investments | |||||||||||||
NDT funds have been established for each generating station unit to satisfy Generation's nuclear decommissioning obligations. Generally, NDT funds established for a particular unit may not be used to fund the decommissioning obligations of another unit. | |||||||||||||
The NDT funds associated with the former ComEd, former PECO and former AmerGen units have been funded with amounts collected from ComEd customers, PECO customers and the previous owners of the former AmerGen plants, respectively. Based on an ICC order, ComEd ceased collecting amounts from its customers to pay for decommissioning costs. PECO is authorized to collect funds, in revenues, for decommissioning the former PECO nuclear plants through regulated rates, and these collections are scheduled through the operating lives of the plants. The amounts collected from PECO customers are remitted to Generation and deposited into the NDT funds for the unit for which funds are collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO's calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. The most recent rate adjustment occurred on January 1, 2013, and the effective rates currently yield annual collections of approximately $24 million. The next five-year adjustment is expected to be reflected in rates charged to PECO customers effective January 1, 2018. With respect to the former AmerGen units, Generation does not collect any amounts, nor is there any mechanism by which Generation can seek to collect additional amounts, from customers. Apart from the contributions made to the NDT funds from amounts collected from ComEd and PECO customers, Generation has not made contributions to the NDT funds. | |||||||||||||
Any shortfall of funds necessary for decommissioning, determined for each generating station unit, is ultimately required to be funded by Generation, with the exception of a shortfall for the current decommissioning activities at Zion Station, where certain decommissioning activities have been transferred to a third party (see Zion Station Decommissioning below). Generation has recourse to collect additional amounts from PECO customers related to a shortfall of NDT funds for the former PECO units, subject to certain limitations and thresholds, as prescribed by an order from the PAPUC. Generally, PECO will not be allowed to collect amounts associated with the first $50 million of any shortfall of trust funds, on an aggregate basis for all former PECO units, compared to decommissioning obligations, as well as 5% of any additional shortfalls. The initial $50 million and up to 5% of any additional shortfalls would be borne by Generation. No recourse exists to collect additional amounts from ComEd customers for the former ComEd units or from the previous owners of the former AmerGen units. With respect to the former ComEd and PECO units, any funds remaining in the NDTs after all decommissioning has been completed are required to be refunded to ComEd's or PECO's customers, subject to certain limitations that allow sharing of excess funds with Generation related to the former PECO units. With respect to the former AmerGen units, Generation retains any funds remaining in the funds after decommissioning. | |||||||||||||
At September 30, 2013 and December 31, 2012, Exelon and Generation had NDT fund investments totaling $7,776 million and $7,248 million, respectively. The following table provides unrealized gains (losses) on NDT funds for the three and nine months ended September 30, 2013 and 2012: | |||||||||||||
Exelon and Generation | |||||||||||||
Three Months Ended | Nine Months Ended | ||||||||||||
September 30, | September 30, | ||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||
Net unrealized gains on decommissioning trust funds — | |||||||||||||
Regulatory Agreement Units (a) | $ | 103 | $ | 202 | $ | 196 | $ | 352 | |||||
Net unrealized gains on decommissioning trust funds — | |||||||||||||
Non-Regulatory Agreement Units (b)(c) | 46 | 71 | 70 | 101 | |||||||||
(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 $9 million of net unrealized losses and $22 million of net unrealized gains related to the Zion Station pledged assets for the three months ended September 30, 2013 and 2012, respectively, and $5 million of net unrealized losses and $60 million of net unrealized gains related to the Zion Station pledged assets for the nine months ended September 30, 2013 and 2012, respectively. Net unrealized gains (losses) 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 associated 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. | |||||||||||||
See Note 3 – Regulatory Matters and Note 22 – Related Party Transactions of the Exelon 2012 Form 10-K 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. On January 7, 2013, EnergySolutions announced that it had entered a definitive acquisition agreement to be 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. See Note 13 – Asset Retirement Obligations of the Exelon 2012 Form 10-K for information regarding the specific treatment of assets, including NDT funds, and decommissioning liabilities transferred in the transaction. | |||||||||||||
On July 14, 2011, three people filed a purported class action lawsuit in the United States District Court for the Northern District of Illinois naming ZionSolutions and Bank of New York Mellon as defendants and seeking, among other things, an accounting for use of NDT funds, an injunction against the use of NDT funds, the appointment of a trustee for the NDT funds, and the return of NDT funds to customers of ComEd to the extent legally entitled thereto. If the plaintiffs prevail on the merits of their claims, some or all of the NDT funds may no longer be available to ZionSolutions for decommissioning Zion Station, in which case, the contractual arrangement would require ZionSolutions to utilize a line of credit to complete the decommissioning. In addition, the appointment of a NDT fund trustee in this matter could impact Generation's future decommissioning activities at other stations by setting a precedent for the appointment of trustees for NDT funds. On July 20, 2012, ZionSolutions and Bank of New York Mellon filed a motion to dismiss the amended complaint for failing to state a claim. On July 29, 2013, United States District Court for the Northern District of Illinois dismissed the amended complaint. On August 26, 2013, the plaintiffs filed a notice of appeal with the United States Court of Appeals for the Seventh Circuit. The parties will submit briefs in support of their positions, following which the Court of Appeals will typically schedule oral argument. | |||||||||||||
ZionSolutions is subject to certain restrictions on its ability to request reimbursements from the Zion Station NDT funds as defined within the ASA. Therefore, the transfer of the Zion Station assets did not qualify for asset sale accounting treatment and, as a result, the related NDT funds were reclassified to pledged assets for Zion Station decommissioning within Generation's and Exelon's Consolidated Balance Sheets and will continue to be measured in the same manner as prior to the completion of the transaction. Additionally, the transferred ARO for decommissioning was replaced with a payable to ZionSolutions in Generation's and Exelon's Consolidated Balance Sheets. Changes in the value of the Zion Station NDT assets, net of applicable taxes, will be recorded as a change in the payable to ZionSolutions. At no point will the payable to ZionSolutions exceed the project budget of the costs remaining to decommission Zion Station. Generation has retained its obligation to the SNF following ZionSolutions completion of its contractual obligations, to transfer the SNF at Zion Station to the DOE for ultimate disposal, and to complete all remaining decommissioning activities associated with the SNF storage facility. Generation has a liability of approximately $81 million, which is included within the nuclear decommissioning ARO at September 30, 2013. Generation also has retained NDT assets to fund its obligation to maintain and transfer the SNF at Zion Station and to complete all remaining decommissioning activities for the SNF storage facility. Any shortage of funds necessary to maintain the SNF and decommission the SNF storage facility is ultimately required to be funded by Generation. Any Zion Station NDT funds remaining after the completion of all decommissioning activities will be returned to ComEd customers in accordance with the applicable orders. The following table provides the pledged assets and payable to ZionSolutions, and withdrawals by ZionSolutions at September 30, 2013 and December 31, 2012: | |||||||||||||
Exelon and Generation | |||||||||||||
September 30, | December 31, | ||||||||||||
2013 | 2012 | ||||||||||||
Carrying value of Zion Station pledged assets | $ | 486 | $ | 614 | |||||||||
Payable to Zion Solutions (a) | 443 | 564 | |||||||||||
Current portion of payable to Zion Solutions (b) | 104 | 132 | |||||||||||
Withdrawals by Zion Solutions to pay decommissioning costs (c) | 458 | 335 | |||||||||||
__________ | |||||||||||||
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. | |||||||||||||
Included in Other current liabilities within Exelon's and Generation's Consolidated Balance Sheets. | |||||||||||||
Cumulative withdrawals since September 1, 2010. | |||||||||||||
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. On April 1, 2013, Generation submitted its NRC-required biennial decommissioning funding status report as of December 31, 2012. As of December 31, 2012, Generation provided adequate funding assurance for all of its units, including Limerick Unit 1, where Generation has in place a $115 million parent guarantee to cover the NRC minimum funding assurance requirements. On October 2, 2013, the NRC issued summary findings from the NRC Staff's review of the 2013 decommissioning funding status reports for all 104 operating reactors, including the Generation operating units. Based on that review, the NRC Staff determined that Generation provided decommissioning funding assurance under the NRC regulations for all of its operating units, including Limerick Unit 1. | |||||||||||||
On January 31, 2013, Generation received a letter from the NRC indicating that the NRC has identified potential “apparent violations” of its regulations because of alleged inaccuracies in the Decommissioning Funding Status reports for 2005, 2006, 2007, and 2009. The NRC asserted that Generation's status reports deliberately reflected cost estimates for decommissioning its nuclear plants that were less than what the NRC says are the minimum amounts required by NRC regulations. Generation met with the NRC on April 30, 2013 for a pre-decisional enforcement conference to provide additional information to explain why Generation believes that it complied with the regulatory requirements and did not deliberately or otherwise provide incomplete or inaccurate information in its decommissioning funding status reports. While Generation does not believe that any sanction is appropriate, the ultimate outcome of this proceeding including the amount of a potential fine or sanction, if any, is uncertain. The January 31, 2013 letter from the NRC does not take issue with Generation's current funding status, and as reflected in Generation's April 1, 2013 decommissioning funding status report referenced above, Generation continues to provide adequate funding assurance for each of its units. In the normal course of NRC review, Generation has received a series of data requests that are unrelated to the potential apparent violations and the pre-decisional enforcement conference. Generation continues to cooperate with the NRC and provide the requested information. Generation does not have a definite date on which it will receive a response from the NRC. Although the government shutdown may delay receipt of a response from the NRC, Generation anticipates that the NRC will issue its findings this year. | |||||||||||||
In addition, on June 24, 2013, Exelon received a subpoena from the SEC requesting that Exelon provide the SEC with certain documents generally relating to Exelon and Generation's reporting and funding of the future decommissioning of Exelon's nuclear power plants. Exelon and Generation are cooperating with the SEC and providing the requested documents. | |||||||||||||
Nuclear_Decommissioning_Exelon
Nuclear Decommissioning (Exelon and Generation) | 9 Months Ended | ||||||||||||
Sep. 30, 2013 | |||||||||||||
Nuclear Decommissioning Disclosure [Line Items] | ' | ||||||||||||
Nuclear Decommissioning (Exelon and Generation) | ' | ||||||||||||
13. Nuclear Decommissioning (Exelon and Generation) | |||||||||||||
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 December 31, 2012 to September 30, 2013: | |||||||||||||
Nuclear decommissioning ARO at December 31, 2012 (a) | $ | 4,741 | |||||||||||
Accretion expense | 194 | ||||||||||||
Net decrease due to changes in, and timing of, estimated cash flows | -141 | ||||||||||||
Costs incurred to decommission retired plants | -2 | ||||||||||||
Nuclear decommissioning ARO at September 30, 2013 (a) | $ | 4,792 | |||||||||||
(a) Includes $10 million as the current portion of the ARO at September 30, 2013 and December 31, 2012, respectively, which is included in Other current liabilities on Exelon's and Generation's Consolidated Balance Sheets. | |||||||||||||
During the nine months ended September 30, 2013, Generation's ARO increased by approximately $51 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 CARFRs, which have increased from the prior year. The decrease in the ARO due to the changes in, and timing of, estimated cash flows were entirely offset by decreases in Property, plant and equipment within Exelon's and Generation's Consolidated Balance Sheets. | |||||||||||||
During the nine months ended September 30, 2012, Generation's ARO increased by $916 million. The increase in the ARO was largely driven by four factors: i) changes in the timing of the future nominal cash flows resulting from an assumed five year deferral to 2025 of the acceptance date of spent nuclear fuel by the DOE coupled with the fact that; ii) cash flows affected by this change in timing are re-measured and discounted at current CARFRs, which had dramatically decreased given the lower interest rate environment; iii) an increase in the estimated costs to decommission the Quad Cities and Dresden nuclear units resulting from the completion of updated decommissioning costs studies received during 2012; and iv) accretion of the obligation. The increase in the ARO due to the changes in, and timing of, estimated cash flows resulted in $10 million of expense, which is included in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. | |||||||||||||
Nuclear Decommissioning Trust Fund Investments | |||||||||||||
NDT funds have been established for each generating station unit to satisfy Generation's nuclear decommissioning obligations. Generally, NDT funds established for a particular unit may not be used to fund the decommissioning obligations of another unit. | |||||||||||||
The NDT funds associated with the former ComEd, former PECO and former AmerGen units have been funded with amounts collected from ComEd customers, PECO customers and the previous owners of the former AmerGen plants, respectively. Based on an ICC order, ComEd ceased collecting amounts from its customers to pay for decommissioning costs. PECO is authorized to collect funds, in revenues, for decommissioning the former PECO nuclear plants through regulated rates, and these collections are scheduled through the operating lives of the plants. The amounts collected from PECO customers are remitted to Generation and deposited into the NDT funds for the unit for which funds are collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO's calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. The most recent rate adjustment occurred on January 1, 2013, and the effective rates currently yield annual collections of approximately $24 million. The next five-year adjustment is expected to be reflected in rates charged to PECO customers effective January 1, 2018. With respect to the former AmerGen units, Generation does not collect any amounts, nor is there any mechanism by which Generation can seek to collect additional amounts, from customers. Apart from the contributions made to the NDT funds from amounts collected from ComEd and PECO customers, Generation has not made contributions to the NDT funds. | |||||||||||||
Any shortfall of funds necessary for decommissioning, determined for each generating station unit, is ultimately required to be funded by Generation, with the exception of a shortfall for the current decommissioning activities at Zion Station, where certain decommissioning activities have been transferred to a third party (see Zion Station Decommissioning below). Generation has recourse to collect additional amounts from PECO customers related to a shortfall of NDT funds for the former PECO units, subject to certain limitations and thresholds, as prescribed by an order from the PAPUC. Generally, PECO will not be allowed to collect amounts associated with the first $50 million of any shortfall of trust funds, on an aggregate basis for all former PECO units, compared to decommissioning obligations, as well as 5% of any additional shortfalls. The initial $50 million and up to 5% of any additional shortfalls would be borne by Generation. No recourse exists to collect additional amounts from ComEd customers for the former ComEd units or from the previous owners of the former AmerGen units. With respect to the former ComEd and PECO units, any funds remaining in the NDTs after all decommissioning has been completed are required to be refunded to ComEd's or PECO's customers, subject to certain limitations that allow sharing of excess funds with Generation related to the former PECO units. With respect to the former AmerGen units, Generation retains any funds remaining in the funds after decommissioning. | |||||||||||||
At September 30, 2013 and December 31, 2012, Exelon and Generation had NDT fund investments totaling $7,776 million and $7,248 million, respectively. The following table provides unrealized gains (losses) on NDT funds for the three and nine months ended September 30, 2013 and 2012: | |||||||||||||
Exelon and Generation | |||||||||||||
Three Months Ended | Nine Months Ended | ||||||||||||
September 30, | September 30, | ||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||
Net unrealized gains on decommissioning trust funds — | |||||||||||||
Regulatory Agreement Units (a) | $ | 103 | $ | 202 | $ | 196 | $ | 352 | |||||
Net unrealized gains on decommissioning trust funds — | |||||||||||||
Non-Regulatory Agreement Units (b)(c) | 46 | 71 | 70 | 101 | |||||||||
Exelon and Generation | |||||||||||||
September 30, | December 31, | ||||||||||||
2013 | 2012 | ||||||||||||
Carrying value of Zion Station pledged assets | $ | 486 | $ | 614 | |||||||||
Payable to Zion Solutions (a) | 443 | 564 | |||||||||||
Current portion of payable to Zion Solutions (b) | 104 | 132 | |||||||||||
Withdrawals by Zion Solutions to pay decommissioning costs (c) | 458 | 335 | |||||||||||
__________ | |||||||||||||
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. | |||||||||||||
Included in Other current liabilities within Exelon's and Generation's Consolidated Balance Sheets. | |||||||||||||
Cumulative withdrawals since September 1, 2010. | |||||||||||||
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. On April 1, 2013, Generation submitted its NRC-required biennial decommissioning funding status report as of December 31, 2012. As of December 31, 2012, Generation provided adequate funding assurance for all of its units, including Limerick Unit 1, where Generation has in place a $115 million parent guarantee to cover the NRC minimum funding assurance requirements. On October 2, 2013, the NRC issued summary findings from the NRC Staff's review of the 2013 decommissioning funding status reports for all 104 operating reactors, including the Generation operating units. Based on that review, the NRC Staff determined that Generation provided decommissioning funding assurance under the NRC regulations for all of its operating units, including Limerick Unit 1. | |||||||||||||
On January 31, 2013, Generation received a letter from the NRC indicating that the NRC has identified potential “apparent violations” of its regulations because of alleged inaccuracies in the Decommissioning Funding Status reports for 2005, 2006, 2007, and 2009. The NRC asserted that Generation's status reports deliberately reflected cost estimates for decommissioning its nuclear plants that were less than what the NRC says are the minimum amounts required by NRC regulations. Generation met with the NRC on April 30, 2013 for a pre-decisional enforcement conference to provide additional information to explain why Generation believes that it complied with the regulatory requirements and did not deliberately or otherwise provide incomplete or inaccurate information in its decommissioning funding status reports. While Generation does not believe that any sanction is appropriate, the ultimate outcome of this proceeding including the amount of a potential fine or sanction, if any, is uncertain. The January 31, 2013 letter from the NRC does not take issue with Generation's current funding status, and as reflected in Generation's April 1, 2013 decommissioning funding status report referenced above, Generation continues to provide adequate funding assurance for each of its units. In the normal course of NRC review, Generation has received a series of data requests that are unrelated to the potential apparent violations and the pre-decisional enforcement conference. Generation continues to cooperate with the NRC and provide the requested information. Generation does not have a definite date on which it will receive a response from the NRC. Although the government shutdown may delay receipt of a response from the NRC, Generation anticipates that the NRC will issue its findings this year. | |||||||||||||
In addition, on June 24, 2013, Exelon received a subpoena from the SEC requesting that Exelon provide the SEC with certain documents generally relating to Exelon and Generation's reporting and funding of the future decommissioning of Exelon's nuclear power plants. Exelon and Generation are cooperating with the SEC and providing the requested documents. | |||||||||||||
Exelon Generation Co L L C [Member] | ' | ||||||||||||
Nuclear Decommissioning Disclosure [Line Items] | ' | ||||||||||||
Nuclear Decommissioning (Exelon and Generation) | ' | ||||||||||||
13. Nuclear Decommissioning (Exelon and Generation) | |||||||||||||
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 December 31, 2012 to September 30, 2013: | |||||||||||||
Nuclear decommissioning ARO at December 31, 2012 (a) | $ | 4,741 | |||||||||||
Accretion expense | 194 | ||||||||||||
Net decrease due to changes in, and timing of, estimated cash flows | -141 | ||||||||||||
Costs incurred to decommission retired plants | -2 | ||||||||||||
Nuclear decommissioning ARO at September 30, 2013 (a) | $ | 4,792 | |||||||||||
(a) Includes $10 million as the current portion of the ARO at September 30, 2013 and December 31, 2012, respectively, which is included in Other current liabilities on Exelon's and Generation's Consolidated Balance Sheets. | |||||||||||||
During the nine months ended September 30, 2013, Generation's ARO increased by approximately $51 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 CARFRs, which have increased from the prior year. The decrease in the ARO due to the changes in, and timing of, estimated cash flows were entirely offset by decreases in Property, plant and equipment within Exelon's and Generation's Consolidated Balance Sheets. | |||||||||||||
During the nine months ended September 30, 2012, Generation's ARO increased by $916 million. The increase in the ARO was largely driven by four factors: i) changes in the timing of the future nominal cash flows resulting from an assumed five year deferral to 2025 of the acceptance date of spent nuclear fuel by the DOE coupled with the fact that; ii) cash flows affected by this change in timing are re-measured and discounted at current CARFRs, which had dramatically decreased given the lower interest rate environment; iii) an increase in the estimated costs to decommission the Quad Cities and Dresden nuclear units resulting from the completion of updated decommissioning costs studies received during 2012; and iv) accretion of the obligation. The increase in the ARO due to the changes in, and timing of, estimated cash flows resulted in $10 million of expense, which is included in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. | |||||||||||||
Nuclear Decommissioning Trust Fund Investments | |||||||||||||
NDT funds have been established for each generating station unit to satisfy Generation's nuclear decommissioning obligations. Generally, NDT funds established for a particular unit may not be used to fund the decommissioning obligations of another unit. | |||||||||||||
The NDT funds associated with the former ComEd, former PECO and former AmerGen units have been funded with amounts collected from ComEd customers, PECO customers and the previous owners of the former AmerGen plants, respectively. Based on an ICC order, ComEd ceased collecting amounts from its customers to pay for decommissioning costs. PECO is authorized to collect funds, in revenues, for decommissioning the former PECO nuclear plants through regulated rates, and these collections are scheduled through the operating lives of the plants. The amounts collected from PECO customers are remitted to Generation and deposited into the NDT funds for the unit for which funds are collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO's calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. The most recent rate adjustment occurred on January 1, 2013, and the effective rates currently yield annual collections of approximately $24 million. The next five-year adjustment is expected to be reflected in rates charged to PECO customers effective January 1, 2018. With respect to the former AmerGen units, Generation does not collect any amounts, nor is there any mechanism by which Generation can seek to collect additional amounts, from customers. Apart from the contributions made to the NDT funds from amounts collected from ComEd and PECO customers, Generation has not made contributions to the NDT funds. | |||||||||||||
Any shortfall of funds necessary for decommissioning, determined for each generating station unit, is ultimately required to be funded by Generation, with the exception of a shortfall for the current decommissioning activities at Zion Station, where certain decommissioning activities have been transferred to a third party (see Zion Station Decommissioning below). Generation has recourse to collect additional amounts from PECO customers related to a shortfall of NDT funds for the former PECO units, subject to certain limitations and thresholds, as prescribed by an order from the PAPUC. Generally, PECO will not be allowed to collect amounts associated with the first $50 million of any shortfall of trust funds, on an aggregate basis for all former PECO units, compared to decommissioning obligations, as well as 5% of any additional shortfalls. The initial $50 million and up to 5% of any additional shortfalls would be borne by Generation. No recourse exists to collect additional amounts from ComEd customers for the former ComEd units or from the previous owners of the former AmerGen units. With respect to the former ComEd and PECO units, any funds remaining in the NDTs after all decommissioning has been completed are required to be refunded to ComEd's or PECO's customers, subject to certain limitations that allow sharing of excess funds with Generation related to the former PECO units. With respect to the former AmerGen units, Generation retains any funds remaining in the funds after decommissioning. | |||||||||||||
At September 30, 2013 and December 31, 2012, Exelon and Generation had NDT fund investments totaling $7,776 million and $7,248 million, respectively. The following table provides unrealized gains (losses) on NDT funds for the three and nine months ended September 30, 2013 and 2012: | |||||||||||||
Exelon and Generation | |||||||||||||
Three Months Ended | Nine Months Ended | ||||||||||||
September 30, | September 30, | ||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||
Net unrealized gains on decommissioning trust funds — | |||||||||||||
Regulatory Agreement Units (a) | $ | 103 | $ | 202 | $ | 196 | $ | 352 | |||||
Net unrealized gains on decommissioning trust funds — | |||||||||||||
Non-Regulatory Agreement Units (b)(c) | 46 | 71 | 70 | 101 | |||||||||
(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 $9 million of net unrealized losses and $22 million of net unrealized gains related to the Zion Station pledged assets for the three months ended September 30, 2013 and 2012, respectively, and $5 million of net unrealized losses and $60 million of net unrealized gains related to the Zion Station pledged assets for the nine months ended September 30, 2013 and 2012, respectively. Net unrealized gains (losses) 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 associated 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. | |||||||||||||
See Note 3 – Regulatory Matters and Note 22 – Related Party Transactions of the Exelon 2012 Form 10-K 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. On January 7, 2013, EnergySolutions announced that it had entered a definitive acquisition agreement to be 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. See Note 13 – Asset Retirement Obligations of the Exelon 2012 Form 10-K for information regarding the specific treatment of assets, including NDT funds, and decommissioning liabilities transferred in the transaction. | |||||||||||||
On July 14, 2011, three people filed a purported class action lawsuit in the United States District Court for the Northern District of Illinois naming ZionSolutions and Bank of New York Mellon as defendants and seeking, among other things, an accounting for use of NDT funds, an injunction against the use of NDT funds, the appointment of a trustee for the NDT funds, and the return of NDT funds to customers of ComEd to the extent legally entitled thereto. If the plaintiffs prevail on the merits of their claims, some or all of the NDT funds may no longer be available to ZionSolutions for decommissioning Zion Station, in which case, the contractual arrangement would require ZionSolutions to utilize a line of credit to complete the decommissioning. In addition, the appointment of a NDT fund trustee in this matter could impact Generation's future decommissioning activities at other stations by setting a precedent for the appointment of trustees for NDT funds. On July 20, 2012, ZionSolutions and Bank of New York Mellon filed a motion to dismiss the amended complaint for failing to state a claim. On July 29, 2013, United States District Court for the Northern District of Illinois dismissed the amended complaint. On August 26, 2013, the plaintiffs filed a notice of appeal with the United States Court of Appeals for the Seventh Circuit. The parties will submit briefs in support of their positions, following which the Court of Appeals will typically schedule oral argument. | |||||||||||||
ZionSolutions is subject to certain restrictions on its ability to request reimbursements from the Zion Station NDT funds as defined within the ASA. Therefore, the transfer of the Zion Station assets did not qualify for asset sale accounting treatment and, as a result, the related NDT funds were reclassified to pledged assets for Zion Station decommissioning within Generation's and Exelon's Consolidated Balance Sheets and will continue to be measured in the same manner as prior to the completion of the transaction. Additionally, the transferred ARO for decommissioning was replaced with a payable to ZionSolutions in Generation's and Exelon's Consolidated Balance Sheets. Changes in the value of the Zion Station NDT assets, net of applicable taxes, will be recorded as a change in the payable to ZionSolutions. At no point will the payable to ZionSolutions exceed the project budget of the costs remaining to decommission Zion Station. Generation has retained its obligation to the SNF following ZionSolutions completion of its contractual obligations, to transfer the SNF at Zion Station to the DOE for ultimate disposal, and to complete all remaining decommissioning activities associated with the SNF storage facility. Generation has a liability of approximately $81 million, which is included within the nuclear decommissioning ARO at September 30, 2013. Generation also has retained NDT assets to fund its obligation to maintain and transfer the SNF at Zion Station and to complete all remaining decommissioning activities for the SNF storage facility. Any shortage of funds necessary to maintain the SNF and decommission the SNF storage facility is ultimately required to be funded by Generation. Any Zion Station NDT funds remaining after the completion of all decommissioning activities will be returned to ComEd customers in accordance with the applicable orders. The following table provides the pledged assets and payable to ZionSolutions, and withdrawals by ZionSolutions at September 30, 2013 and December 31, 2012: | |||||||||||||
Exelon and Generation | |||||||||||||
September 30, | December 31, | ||||||||||||
2013 | 2012 | ||||||||||||
Carrying value of Zion Station pledged assets | $ | 486 | $ | 614 | |||||||||
Payable to Zion Solutions (a) | 443 | 564 | |||||||||||
Current portion of payable to Zion Solutions (b) | 104 | 132 | |||||||||||
Withdrawals by Zion Solutions to pay decommissioning costs (c) | 458 | 335 | |||||||||||
__________ | |||||||||||||
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. | |||||||||||||
Included in Other current liabilities within Exelon's and Generation's Consolidated Balance Sheets. | |||||||||||||
Cumulative withdrawals since September 1, 2010. | |||||||||||||
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. On April 1, 2013, Generation submitted its NRC-required biennial decommissioning funding status report as of December 31, 2012. As of December 31, 2012, Generation provided adequate funding assurance for all of its units, including Limerick Unit 1, where Generation has in place a $115 million parent guarantee to cover the NRC minimum funding assurance requirements. On October 2, 2013, the NRC issued summary findings from the NRC Staff's review of the 2013 decommissioning funding status reports for all 104 operating reactors, including the Generation operating units. Based on that review, the NRC Staff determined that Generation provided decommissioning funding assurance under the NRC regulations for all of its operating units, including Limerick Unit 1. | |||||||||||||
On January 31, 2013, Generation received a letter from the NRC indicating that the NRC has identified potential “apparent violations” of its regulations because of alleged inaccuracies in the Decommissioning Funding Status reports for 2005, 2006, 2007, and 2009. The NRC asserted that Generation's status reports deliberately reflected cost estimates for decommissioning its nuclear plants that were less than what the NRC says are the minimum amounts required by NRC regulations. Generation met with the NRC on April 30, 2013 for a pre-decisional enforcement conference to provide additional information to explain why Generation believes that it complied with the regulatory requirements and did not deliberately or otherwise provide incomplete or inaccurate information in its decommissioning funding status reports. While Generation does not believe that any sanction is appropriate, the ultimate outcome of this proceeding including the amount of a potential fine or sanction, if any, is uncertain. The January 31, 2013 letter from the NRC does not take issue with Generation's current funding status, and as reflected in Generation's April 1, 2013 decommissioning funding status report referenced above, Generation continues to provide adequate funding assurance for each of its units. In the normal course of NRC review, Generation has received a series of data requests that are unrelated to the potential apparent violations and the pre-decisional enforcement conference. Generation continues to cooperate with the NRC and provide the requested information. Generation does not have a definite date on which it will receive a response from the NRC. Although the government shutdown may delay receipt of a response from the NRC, Generation anticipates that the NRC will issue its findings this year. | |||||||||||||
In addition, on June 24, 2013, Exelon received a subpoena from the SEC requesting that Exelon provide the SEC with certain documents generally relating to Exelon and Generation's reporting and funding of the future decommissioning of Exelon's nuclear power plants. Exelon and Generation are cooperating with the SEC and providing the requested documents. | |||||||||||||
Retirement_Benefits_Exelon_Gen
Retirement Benefits (Exelon, Generation, ComEd, PECO and BGE) | 9 Months Ended | |||||||||||||
Sep. 30, 2013 | ||||||||||||||
Retirement Benefits [Line Items] | ' | |||||||||||||
Retirement Benefits (Exelon, Generation, ComEd, PECO and BGE) | ' | |||||||||||||
14. 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. | ||||||||||||||
Defined Benefit Pension and Other Postretirement Benefits | ||||||||||||||
During the first quarter of 2013, Exelon received an updated valuation of its legacy pension and other postretirement benefit obligations to reflect actual census data as of January 1, 2013. This valuation resulted in an increase to the pension obligation of $8 million and a decrease to the other postretirement benefit obligation of $39 million. Additionally, accumulated other comprehensive loss decreased by approximately $75 million (after tax) and regulatory assets increased by approximately $93 million. During the second quarter of 2013, Exelon received the updated valuation for the legacy Constellation pension and other postretirement obligations to reflect actual census data as of January 1, 2013. This valuation resulted in an increase to the pension obligation of $23 million and a decrease to the other postretirement benefit obligation of $12 million. Additionally, accumulated other comprehensive loss increased by approximately $2 million (after tax) and regulatory assets increased by approximately $14 million. | ||||||||||||||
The following tables present the components of Exelon's net periodic benefit costs for the three and nine months ended September 30, 2013 and 2012. The 2013 pension benefit cost for all plans is calculated using an expected long-term rate of return on plan assets of 7.50% and a discount rate of 3.92%. The 2013 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 6.45% for funded plans and a discount rate of 4.00% for all plans. Certain other postretirement benefit plans are not funded. A portion of the net periodic benefit cost is capitalized within the Consolidated Balance Sheets. | ||||||||||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||||
Three Months Ended | Three Months Ended | |||||||||||||
September 30, | September 30, | |||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||
Service cost | $ | 79 | $ | 76 | $ | 41 | $ | 38 | ||||||
Interest cost | 163 | 181 | 48 | 53 | ||||||||||
Expected return on assets | -253 | -258 | -33 | -28 | ||||||||||
Amortization of: | ||||||||||||||
Transition obligation | 0 | 0 | 0 | 2 | ||||||||||
Prior service cost (benefit) | 3 | 5 | -4 | -3 | ||||||||||
Actuarial loss | 140 | 117 | 20 | 19 | ||||||||||
Settlement charges | 9 | 9 | 0 | 0 | ||||||||||
Curtailment gain | 0 | 0 | 0 | -5 | ||||||||||
Net periodic benefit cost | $ | 141 | $ | 130 | $ | 72 | $ | 76 | ||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||||
Nine Months Ended | Nine Months Ended | |||||||||||||
September 30, | September 30, | |||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||
Service cost | $ | 238 | $ | 211 | $ | 122 | $ | 114 | ||||||
Interest cost | 488 | 524 | 145 | 157 | ||||||||||
Expected return on assets | -761 | -742 | -99 | -86 | ||||||||||
Amortization of: | ||||||||||||||
Transition obligation | 0 | 0 | 0 | 8 | ||||||||||
Prior service cost (benefit) | 10 | 12 | -14 | -10 | ||||||||||
Actuarial loss | 421 | 338 | 62 | 58 | ||||||||||
Settlement charges | 9 | 9 | 0 | 0 | ||||||||||
Contractual termination benefit cost (a) | 0 | 14 | 0 | 6 | ||||||||||
Curtailment gain | 0 | 0 | 0 | -7 | ||||||||||
Net periodic benefit cost | $ | 405 | $ | 366 | $ | 216 | $ | 240 | ||||||
ComEd and BGE established regulatory assets of $1 million and $4 million, respectively, for their portion of the second quarter 2012 contractual termination benefit charge. | ||||||||||||||
The amounts below were included in Capital expenditures and Operating and maintenance expense during the three and nine months ended September 30, 2013 and 2012, for Generation's, ComEd's, PECO's, BGE's and BSC's allocated portion of the pension and postretirement benefit plan costs. | ||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||
September 30, | September 30, | |||||||||||||
Pension and Other Postretirement Benefit Costs | 2013 | 2012 | 2013 | 2012 | ||||||||||
Generation | $ | 87 | $ | 85 | $ | 259 | $ | 259 | ||||||
ComEd | 77 | 75 | 231 | 212 | ||||||||||
PECO | 11 | 12 | 32 | 38 | ||||||||||
BGE (a)(b) | 14 | 14 | 41 | 46 | ||||||||||
BSC (c) | 24 | 20 | 58 | 63 | ||||||||||
(a) BGE's pension and postretirement benefit costs for the nine months ended September 30, 2012 include $12 million of costs incurred prior to the closing of Exelon's merger with Constellation on March 12, 2012. These amounts are not included in Exelon's net periodic benefit costs for the nine months ended September 30, 2012 shown in the first table of the Defined Benefit Pension and Other Postretirement Benefits section above. | ||||||||||||||
(b) BGE's pension and other postretirement benefit costs for the three and nine months ended September 30, 2012 includes a $3 million contractual termination benefit charge, which was recorded as a regulatory asset as of September 30, 2012. | ||||||||||||||
(c) 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 September 30, 2012, ComEd and BGE each recorded a regulatory asset of $1 million related to their BSC-billed portion of the second quarter 2012 contractual termination benefit charge. | ||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||
September 30, | September 30, | |||||||||||||
Savings Plan Matching Contributions | 2013 | 2012 | 2013 | 2012 | ||||||||||
Exelon | $ | 18 | $ | 19 | $ | 61 | $ | 55 | ||||||
Generation | 8 | 9 | 29 | 25 | ||||||||||
ComEd | 6 | 5 | 16 | 14 | ||||||||||
PECO | 2 | 2 | 6 | 5 | ||||||||||
BGE (a) | 1 | 1 | 5 | 5 | ||||||||||
BSC (b) | 1 | 2 | 5 | 6 | ||||||||||
BGE's matching contributions for the nine months ended September 30, 2012 include $1 million of costs incurred prior to the closing of Exelon's merger with Constellation on March 12, 2012, which is not included in Exelon's matching contributions for the nine months ended September 30, 2012. | ||||||||||||||
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. | ||||||||||||||
StockBased_Compensation_Plans_
Stock-Based Compensation Plans (Exelon, Generation, ComEd, PECO and BGE) | 9 Months Ended | ||||||||||||
Sep. 30, 2013 | |||||||||||||
Stock-Based Compensation Plans [Line Items] | ' | ||||||||||||
Stock-Based Compensation Plans (Exelon, Generation, ComEd, PECO and BGE) | ' | ||||||||||||
15. Stock-Based Compensation Plans (Exelon, Generation, ComEd, PECO and BGE) | |||||||||||||
Exelon grants stock-based awards through its LTIP, which primarily includes stock options, restricted stock units and performance share awards. At September 30, 2013, there were approximately 16 million shares authorized for issuance under the LTIP. For the three and nine months ended September 30, 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 performance shares and restricted stock. The performance share awards granted in 2013 will 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 performance period, the Compensation Committee also approved a one-time grant of performance share transition awards in 2013, which will vest one-third after one year, with the remaining balance vesting over a two-year performance period. | |||||||||||||
The following table presents the stock-based compensation expense included in Exelon's Consolidated Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2013 and 2012: | |||||||||||||
Three Months Ended | Nine Months Ended | ||||||||||||
September 30, | September 30, | ||||||||||||
Components of Stock-Based Compensation Expense | 2013 | 2012 | 2013 | 2012 | |||||||||
Performance share awards | $ | 12 | $ | 5 | $ | 41 | $ | 32 | |||||
Stock options | 1 | 2 | 3 | 13 | |||||||||
Restricted stock units | 13 | 12 | 49 | 41 | |||||||||
Other stock-based awards | 1 | 1 | 4 | 3 | |||||||||
Total stock-based compensation expense included in | |||||||||||||
operating and maintenance expense | 27 | 20 | 97 | 89 | |||||||||
Income tax benefit | -10 | -8 | -37 | -34 | |||||||||
Total after-tax stock-based compensation expense | $ | 17 | $ | 12 | $ | 60 | $ | 55 | |||||
The following table presents stock-based compensation expense (pre-tax) for the three and nine months ended September 30, 2013 and 2012: | |||||||||||||
Three Months Ended | Nine Months Ended | ||||||||||||
September 30, | September 30, | ||||||||||||
Subsidiaries | 2013 | 2012 | 2013 | 2012 | |||||||||
Generation | $ | 10 | $ | 9 | $ | 38 | $ | 33 | |||||
ComEd | 3 | 2 | 7 | 9 | |||||||||
PECO | 1 | 1 | 4 | 4 | |||||||||
BGE (a) | 1 | 1 | 5 | 4 | |||||||||
BSC (b) | 12 | 7 | 43 | 39 | |||||||||
Total (c) | $ | 27 | $ | 20 | $ | 97 | $ | 89 | |||||
(a) BGE's stock-based compensation expense (pre-tax) for the nine months ended September 30, 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 nine months ended September 30, 2012 shown in the tables titled Components of Stock-Based Compensation Expense and Subsidiaries above. | |||||||||||||
(b) These amounts primarily represent amounts billed to Exelon's subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO and BGE amounts above. | |||||||||||||
(c) The stock-based compensation expense (pre-tax) for the three and nine months ended September 30, 2013 reflects the impact of changes to the retirement eligibility requirements for employees participating in the LTIP. In addition, the stock-based compensation expense at ComEd reflects the adoption of the ComEd Key Manager Long-Term Performance Program in 2013 for certain employees, which is not considered stock-based compensation expense under the applicable authoritative guidance. In 2012, these employees participated in the Exelon Restricted Stock Award Program. | |||||||||||||
There were no significant stock-based compensation costs capitalized during the three and nine months ended September 30, 2013 and 2012. | |||||||||||||
Stock Options | |||||||||||||
Non-qualified stock options are granted under the LTIP with exercise prices equal to the fair market value of the underlying stock at the date of grant. Generally, the stock options vest ratably over a four-year vesting period and expire ten years from the date of grant. | |||||||||||||
There were no stock options granted in 2013. The Compensation Committee eliminated stock option grants by changing the mix of long-term incentives for senior vice presidents (SVPs) and higher officers from 75% performance shares and 25% stock options to 67% performance shares and 33% restricted stock units (“RSUs”). | |||||||||||||
At September 30, 2013, $3 million of total unrecognized compensation costs related to nonvested stock options are expected to be recognized over the remaining weighted-average period of 1.8 years. | |||||||||||||
Restricted Stock Units | |||||||||||||
Restricted stock units are granted under the LTIP with the majority being settled in a specific number of shares of common stock after the service condition has been met. The corresponding cost of services is measured based on the grant date fair value of the restricted stock unit issued. The 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. | |||||||||||||
At September 30, 2013 and December 31, 2012, Exelon had obligations related to outstanding restricted stock units not yet settled of $67 million and $58 million, respectively, which are included in common stock in Exelon's Consolidated Balance Sheets. As of September 30, 2013 and December 31, 2012, Exelon had no obligations related to outstanding restricted stock units that will be settled in cash. During the three months ended September 30, 2013 and 2012, Exelon settled restricted stock units with a fair value totaling $3 million and $4 million, respectively. During the nine months ended September 30, 2013 and 2012, Exelon settled restricted stock units with a fair value totaling $26 million and $23 million, respectively. At September 30, 2013, $69 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the remaining weighted-average period of 2.2 years. | |||||||||||||
Performance Share and Performance Share Transition Awards | |||||||||||||
Performance share awards are granted under the LTIP with the 2013 performance share awards 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 2012 performance share awards are being settled 50% in common stock and 50% in cash over the three-year vesting term with executive vice presidents and higher officers receiving 100% cash if certain ownership requirements are satisfied. The performance shares granted prior to 2012 generally vest and settle over a three-year period with the holders receiving shares of common stock and/or cash annually during the vesting period. | |||||||||||||
The one-time 2013 performance share transition awards, which provide an opportunity to earn an award contingent on company performance, will be settled 50% in common stock and 50% in cash, except for awards granted to executive vice presidents and higher officers that may be settled 100% in cash if certain ownership requirements are satisfied. One-third of the award vests and is payable after a one-year performance period while the remaining two-thirds vests and is payable after a two-year performance period. | |||||||||||||
The payout of the 2013 performance share awards and one-time performance share transition awards are based on the Company's performance against specific operational and financial goals set annually during the respective performance periods. As a result, the 2013 performance share awards have been divided into equal tranches for the purpose of expense recognition as though the respective award were multiple awards; with each tranche representing a corresponding fiscal year. The one-time performance share transition awards have also been divided into multiple tranches for the purpose of expense recognition. One tranche reflects the one-third of the awards that vests and are payable after a one-year period. The two-thirds of the one-time performance share transition awards that are subject to a two-year performance period have also been divided into equal tranches; with each tranche representing a corresponding fiscal year. The grant date for each tranche of the 2013 performance share and one-time performance share transition awards is the date in which the performance goals for that fiscal year are approved and communicated, which typically occurs at the corresponding January Compensation Committee meeting. | |||||||||||||
The 2013 performance share awards and one-time performance share transition awards are recorded at fair value at the grant dates for each tranche, with the estimated grant date fair value based on the expected payout of the award, which may range from 50% to 150% of the payout target. The 2013 performance share awards also include a total shareholder return modifier (TSR) that may increase or decrease the award up to 25% and an individual performance modifier (IPM) that can decrease the award by up to 50% or increase the award by up to 10% for senior vice presidents and higher officers or up to 20% for vice presidents. The one-time performance share transition award is not affected by either TSR or the IPM. | |||||||||||||
The common stock portion of the performance share and one-time performance share transition awards is considered an equity award being valued based on Exelon's stock price on the grant date. The cash portion of the awards is considered a liability award which is remeasured each reporting period based on Exelon's current stock price. As the value of the common stock and cash portions of the awards are based on Exelon's stock price during the performance period, coupled with changes in the total shareholder return modifier and expected payout of the award, the compensation costs are subject to volatility until payout is established. | |||||||||||||
The 2012 performance share awards are recorded at fair value at the date of grant with the estimated grant date fair value based on the expected payout of the award, which may range from 75% to 125% of the payout target. The common stock portion is considered an equity award with the 75% payout floor being valued based on Exelon's stock price on the grant date. The cash portion of the award is considered a liability award with the 75% payout floor being remeasured each reporting period based on Exelon's current stock price. The expected payout in excess of the 75% floor for the equity and liability portions are remeasured each reporting period based on Exelon's current stock price and changes in the expected payout of the award; therefore these portions of the award are subject to volatility until the payout is established. | |||||||||||||
For nonretirement-eligible employees, stock-based compensation costs are recognized over the vesting period of three years using the graded-vesting method. For performance share and one-time performance share transition awards granted to retirement-eligible employees, the value of the performance shares in recognized ratably over the vesting period, which is the year of grant. | |||||||||||||
At September 30, 2013 and December 31, 2012, Exelon had obligations related to outstanding performance shares not yet settled of $63 million and $53 million, respectively. During the three months ended September 30, 2013 and 2012, Exelon settled performance shares with a fair value totaling $3 million and $3 million, respectively, of which $3 million and $0 million was paid in cash, respectively. During the nine months ended September 30, 2013 and 2012, Exelon settled performance shares with a fair value totaling $25 million and $22 million, respectively, of which $12 million and $3 million was paid in cash, respectively. As of September 30, 2013, $32 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 2.3 years. In addition, as of September 30, 2013, $19 million of total unrecognized compensation costs related to nonvested one-time performance share transition awards are expected to be recognized over the remaining weighted-average period of 1.3 years. | |||||||||||||
Changes_in_Accumulated_Other_C
Changes in Accumulated Other Comprehensive Income (Exelon, Generation, ComEd, PECO and BGE) | 9 Months Ended | |||||||||||||||
Sep. 30, 2013 | Sep. 30, 2012 | |||||||||||||||
Accumulated Other Comprehensive Income Loss [Line Items] | ' | ' | ||||||||||||||
Accumulated Other Comprehensive Income Loss [Text Block] | ' | [1] | ' | |||||||||||||
Gains and (Losses) on Cash Flow Hedges | Unrealized Gains and (Losses) on Marketable Securities | Pension and Non-Pension Postretirement Benefit Plan items | Foreign Currency Items | AOCI of Equity Investments | Total | 16. Changes in Accumulated Other Comprehensive Income (Exelon, Generation, and PECO) | ||||||||||
Exelon (a) | ||||||||||||||||
Beginning balance | $ | 368 | $ | - | $ | -3,137 | $ | - | $ | 2 | $ | -2,767 | The following table presents changes in accumulated other comprehensive income (loss) (AOCI) by component for nine months ended September 30, 2013: | |||
OCI before reclassifications | 25 | -1 | 73 | -5 | 46 | 138 | ||||||||||
Amounts reclassified from AOCI (b) | -194 | - | 157 | - | 5 | -32 | ||||||||||
Net current-period OCI | -169 | -1 | 230 | -5 | 51 | 106 | ||||||||||
Ending balance | $ | 199 | $ | -1 | $ | -2,907 | $ | -5 | $ | 53 | $ | -2,661 | ||||
Generation (a) | ||||||||||||||||
Beginning balance | $ | 512 | $ | - | $ | - | $ | - | $ | 1 | $ | 513 | ||||
OCI before reclassifications | 12 | -1 | - | -5 | 47 | 53 | ||||||||||
Amounts reclassified from AOCI (b) | -328 | - | - | - | 5 | -323 | ||||||||||
Net current-period OCI | -316 | -1 | - | -5 | 52 | -270 | ||||||||||
Ending balance | $ | 196 | $ | -1 | $ | - | $ | -5 | $ | 53 | $ | 243 | ||||
ComEd (a) | ||||||||||||||||
PECO (a) | ||||||||||||||||
Beginning balance | $ | - | $ | 1 | $ | - | $ | - | $ | - | $ | 1 | ||||
OCI before reclassifications | - | - | - | - | - | - | ||||||||||
Amounts reclassified from AOCI (b) | - | - | - | - | - | - | ||||||||||
Net current-period OCI | - | - | - | - | - | - | ||||||||||
Ending balance | $ | - | $ | 1 | $ | - | $ | - | $ | - | $ | 1 | ||||
BGE (a) | ||||||||||||||||
(a) All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income. | ||||||||||||||||
(b) See next table for details about these reclassifications. | ||||||||||||||||
ComEd, PECO, and BGE did not have any reclassifications out of AOCI to Net Income during the three and nine months ended September 30, 2013. The following table presents amounts reclassified out of AOCI to Net Income for Exelon and Generation during the three and nine months ended September 30, 2013: | ||||||||||||||||
Three Months Ended September 30, 2013 | ||||||||||||||||
Details about AOCI components | Items reclassified out of AOCI (a) | Affected line item in the statement where Net Income is presented | ||||||||||||||
Exelon | Generation | |||||||||||||||
Gains and (losses) on cash flow hedges | ||||||||||||||||
Energy related hedges | $ | 84 | $ | 84 | Operating revenues | |||||||||||
Other cash flow hedges | -1 | -1 | Interest expense | |||||||||||||
83 | 83 | Total before tax | ||||||||||||||
-35 | -33 | Tax (expense) | ||||||||||||||
$ | 48 | $ | 50 | Net of tax | ||||||||||||
Gains and (losses) on available for sale securities | ||||||||||||||||
Amortization of pension and other postretirement benefit plan items | ||||||||||||||||
Actuarial losses | -92 | - | (b) | |||||||||||||
Deferred compensation unit plan | -1 | - | (c) | |||||||||||||
-93 | - | Total before tax | ||||||||||||||
37 | - | Tax benefit | ||||||||||||||
$ | -56 | $ | - | Net of tax | ||||||||||||
Equity investments | ||||||||||||||||
Total Reclassifications | ||||||||||||||||
for the period | $ | -8 | $ | 50 | Net of Tax | |||||||||||
Nine Months Ended September 30, 2013 | ||||||||||||||||
Details about AOCI components | Items reclassified out of AOCI (a) | Affected line item in the statement where Net Income is presented | ||||||||||||||
Exelon | Generation | |||||||||||||||
Gains and (losses) on cash flow hedges | ||||||||||||||||
Energy related hedges | $ | 324 | $ | 543 | Operating revenues | |||||||||||
Other cash flow hedges | -2 | - | Interest expense | |||||||||||||
322 | 543 | Total before tax | ||||||||||||||
-128 | -215 | Tax (expense) | ||||||||||||||
$ | 194 | $ | 328 | Net of tax | ||||||||||||
Gains and (losses) on available for sale securities | ||||||||||||||||
Amortization of pension and other postretirement benefit plan items | ||||||||||||||||
Prior service costs | $ | -1 | $ | - | (b) | |||||||||||
Actuarial losses | -257 | - | (b) | |||||||||||||
Deferred compensation unit plan | -1 | - | (c) | |||||||||||||
-259 | - | Total before tax | ||||||||||||||
102 | - | Tax benefit | ||||||||||||||
$ | -157 | $ | - | 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 | ||||||||||||||||
for the period | $ | 32 | $ | 323 | Net of Tax | |||||||||||
(a) All amounts are net of tax. 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 14 for additional details). | ||||||||||||||||
(c) Amortization of deferred compensation unit is allocated to capital and operating and maintenance expense. | ||||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||||
Exelon | ||||||||||||||||
Pension and non-pension postretirement benefit plans: | ||||||||||||||||
Prior service benefit reclassified to periodic benefit cost | $ | 0 | $ | 1 | $ | 0 | $ | 2 | ||||||||
Actuarial loss reclassified to periodic cost | 33 | 28 | 97 | 82 | ||||||||||||
Transition obligation reclassified to periodic cost | 0 | 1 | 0 | 2 | ||||||||||||
Pension and non-pension postretirement benefit | ||||||||||||||||
plans valuation adjustment | -6 | -43 | 44 | -51 | ||||||||||||
Deferred compensation unit valuation adjustment | 0 | 0 | 6 | 0 | ||||||||||||
Change in unrealized loss on cash flow hedges | -35 | -57 | -109 | 36 | ||||||||||||
Change in unrealized income on equity investments | 9 | 11 | 32 | 15 | ||||||||||||
Change in unrealized loss on marketable securities | 0 | 0 | 0 | 1 | ||||||||||||
Total | $ | 1 | $ | -59 | $ | 70 | $ | 87 | ||||||||
Generation | ||||||||||||||||
Change in unrealized loss on cash flow hedges | $ | -36 | $ | -113 | $ | -209 | $ | -122 | ||||||||
Change in unrealized income on equity investments | 9 | 11 | 32 | 15 | ||||||||||||
Total | $ | -27 | $ | -102 | $ | -177 | $ | -107 | ||||||||
[1] | (a) All amounts are net of tax. Amounts in parenthesis represent a decrease in net income. |
Earnings_Per_Share_and_Equity_
Earnings Per Share and Equity (Exelon) | 9 Months Ended | ||||||||||||
Sep. 30, 2013 | |||||||||||||
Earnings Per Share and Equity [Abstract] | ' | ||||||||||||
Earnings Per Share and Equity (Exelon) | ' | ||||||||||||
17. Earnings Per Share and Equity (Exelon and PECO) | |||||||||||||
Earnings per Share (Exelon) | |||||||||||||
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 these stock options, performance share awards and restricted stock on the weighted average number of shares outstanding (in millions) used in calculating diluted earnings per share: | |||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||
Net income attributable to common shareholders | $ | 738 | $ | 296 | $ | 1,224 | $ | 782 | |||||
Average common shares outstanding — basic | 857 | 854 | 856 | 804 | |||||||||
Assumed exercise of stock options, performance share awards | |||||||||||||
and restricted stock | 3 | 3 | 4 | 2 | |||||||||
Average common shares outstanding — diluted | 860 | 857 | 860 | 806 | |||||||||
The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 20 million for the three and nine months ended September 30, 2013 and 18 million and 13 million for the three and nine months ended September 30, 2012, respectively. | |||||||||||||
Under share repurchase programs, 35 million shares of common stock are held as treasury stock with a cost of $2.3 billion as of September 30, 2013. In 2008, Exelon management decided to defer indefinitely any share repurchases. | |||||||||||||
Preferred Securities Redemption (Exelon and PECO) | |||||||||||||
On March 25, 2013, PECO announced that it issued a notice of redemption for all of its outstanding preferred securities with a redemption date of May 1, 2013. PECO had $87 million of cumulative preferred securities that were redeemable at its option at any time for the redemption price established when each series of securities were issued. The redemption premium of $6 million is treated as a reduction to Net income to arrive at Net income attributable to common shareholders utilized in the calculation of the earnings per share for Exelon. As a result of the redemption, PECO is now indirectly, wholly-owned by Exelon. |
Commitments_and_Contingencies_
Commitments and Contingencies (Exelon, Generation, ComEd, PECO and BGE) | 9 Months Ended | |||||||||||||||||||||||||
Sep. 30, 2013 | ||||||||||||||||||||||||||
Commitments And Contingencies Tables Disclosure [Line Items] | ' | |||||||||||||||||||||||||
Commitments and Contingencies (Exelon, Generation, ComEd, PECO and BGE) | ' | |||||||||||||||||||||||||
18. Commitments and Contingencies (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||||||||||||
The following is an update to the current status of commitments and contingencies set forth in Note 19 of the Exelon 2012 Form 10-K. | ||||||||||||||||||||||||||
Commitments | ||||||||||||||||||||||||||
Energy Commitments | ||||||||||||||||||||||||||
As of September 30, 2013, Generation's commitments relating to purchases from unaffiliated utilities and others of energy, capacity and transmission rights, are as indicated in the following table: | ||||||||||||||||||||||||||
Net Capacity | REC | Transmission Rights | Purchased Energy | |||||||||||||||||||||||
Purchases (a) | Purchases (b) | Purchases (c) | from CENG | Total | ||||||||||||||||||||||
2013 | $ | 86 | $ | 17 | $ | 7 | $ | 186 | $ | 296 | ||||||||||||||||
2014 | 396 | 124 | 26 | 745 | 1,291 | |||||||||||||||||||||
2015 | 368 | 97 | 13 | — | 478 | |||||||||||||||||||||
2016 | 285 | 57 | 2 | — | 344 | |||||||||||||||||||||
2017 | 223 | 16 | 2 | — | 241 | |||||||||||||||||||||
Thereafter | 526 | 5 | 34 | — | 565 | |||||||||||||||||||||
Total | $ | 1,884 | $ | 316 | $ | 84 | $ | 931 | $ | 3,215 | ||||||||||||||||
(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 September 30, 2013, net of fixed capacity payments expected to be received by Generation under contracts to resell such acquired capacity to third parties under long-term capacity sale contracts. These capacity payments represent the fixed, or pre-determined, payment for output from contracted generation facilities. Output in this context generally includes products such as energy, capacity, and various ancillary services associated with generating facilities. Expected payments include certain capacity charges which are contingent on plant availability. | ||||||||||||||||||||||||||
(b) Power-related purchases include firm REC purchase agreements. 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. | ||||||||||||||||||||||||||
In connection with Constellation's comprehensive agreement with EDF in October 2010, Constellation's and EDF's existing power purchase agreements with CENG were modified to be unit-contingent through the end of their original term in 2014. Under these agreements, CENG has the ability to fix the energy price on a forward basis by entering into monthly energy hedge transactions for a portion of the future sale, while any unhedged portions will be provided at market prices by default. Additionally, beginning in 2015 and continuing to the end of the life of the respective plants, Generation agreed to purchase 50.01% of the available output of CENG's nuclear plants at market prices. Generation discloses in the table above commitments to purchase from CENG at fixed prices. All commitments to purchase at market prices, which include all purchases subsequent to December 31, 2014, are excluded from the table. Generation continues to own a 50.01% membership interest in CENG that is accounted for as an equity method investment. See Note 6 — Investment in Constellation Energy Nuclear Group, LLC for more details on this arrangement. | ||||||||||||||||||||||||||
ComEd's, PECO's and BGE's electric supply procurement, curtailment services, REC and AEC purchase commitments as of September 30, 2013 are as follows: | ||||||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||||
2018 | ||||||||||||||||||||||||||
Total | 2013 | 2014 | 2015 | 2016 | 2017 | and beyond | ||||||||||||||||||||
ComEd | ||||||||||||||||||||||||||
Electric supply procurement (a) | $ | 878 | $ | 142 | $ | 323 | $ | 136 | $ | 137 | $ | 140 | $ | - | ||||||||||||
Renewable energy and RECs (b) | 1,604 | 20 | 67 | 74 | 76 | 77 | 1,290 | |||||||||||||||||||
PECO | ||||||||||||||||||||||||||
Electric supply procurement (c) | 886 | 211 | 584 | 91 | - | - | - | |||||||||||||||||||
AECs | 15 | 1 | 2 | 2 | 2 | 2 | 6 | |||||||||||||||||||
BGE | ||||||||||||||||||||||||||
Electric supply procurement (d) | 1,122 | 227 | 669 | 226 | - | - | - | |||||||||||||||||||
Curtailment services (e) | 147 | 13 | 46 | 41 | 34 | 13 | - | |||||||||||||||||||
(a) ComEd entered into various contracts for the procurement of electricity that started to expire in 2012, and will continue to expire through 2017. ComEd is permitted to recover its electric supply procurement costs from retail customers with no mark-up. See Note 5 – Regulatory Matters for additional information. | ||||||||||||||||||||||||||
(b) ComEd entered into 20-year contracts for renewable energy and RECs beginning June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. Pursuant to the ICC's Order on December 19, 2012, ComEd's commitments under the existing long-term contracts for energy and associated RECs were reduced in the first quarter of 2013. See Note 5 – Regulatory Matters for additional information. | ||||||||||||||||||||||||||
(c) PECO entered into various contracts for the procurement of electric supply to serve its default service customers that expire between 2013 and 2015. PECO is permitted to recover its electric supply procurement costs from default service customers with no mark-up in accordance with its PAPUC-approved DSP Programs. See Note 5 - Regulatory Matters for additional information. | ||||||||||||||||||||||||||
(d) BGE entered into various contracts for the procurement of electricity that expire between 2013 and 2015. The cost of power under these contracts is recoverable under MDPSC approved fuel clauses. See Note 5 - Regulatory Matters for additional information. | ||||||||||||||||||||||||||
(e) BGE has entered into various contracts with curtailment services providers related to transactions in PJM's capacity market. See Note 5 - 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 (and with respect to coal, commitments to sell coal). 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 September 30, 2013, these net commitments were as follows: | ||||||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||||
2018 | ||||||||||||||||||||||||||
Total | 2013 | 2014 | 2015 | 2016 | 2017 | and beyond | ||||||||||||||||||||
Generation | $ | 7,901 | $ | 339 | $ | 1,199 | $ | 1,233 | $ | 1,021 | $ | 1,050 | $ | 3,059 | ||||||||||||
PECO | 477 | 54 | 128 | 100 | 78 | 36 | 81 | |||||||||||||||||||
BGE | 603 | 46 | 123 | 52 | 51 | 50 | 281 | |||||||||||||||||||
Other Purchase Obligations | ||||||||||||||||||||||||||
The Registrants' other purchase obligations as of September 30, 2013, which primarily represent commitments for services, materials and information technology, are as follows: | ||||||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||||
2018 | ||||||||||||||||||||||||||
Total | 2013 | 2014 | 2015 | 2016 | 2017 | and beyond | ||||||||||||||||||||
Exelon | $ | 269 | $ | 33 | $ | 38 | $ | 32 | $ | 31 | $ | 31 | $ | 104 | ||||||||||||
Generation | 628 | 133 | 178 | 127 | 40 | 38 | 112 | |||||||||||||||||||
ComEd (a) | 82 | 7 | 41 | 5 | 5 | 5 | 19 | |||||||||||||||||||
PECO (a) | 54 | 19 | 25 | 1 | 1 | 1 | 7 | |||||||||||||||||||
BGE (a) | 25 | 2 | 21 | 2 | — | — | — | |||||||||||||||||||
____________________ | ||||||||||||||||||||||||||
(a) Purchase obligations include commitments related to smart meter installation. See Note 5 - Regulatory Matters for additional information. | ||||||||||||||||||||||||||
Construction Commitments | ||||||||||||||||||||||||||
Generation has committed to the construction of a solar PV facility in Los Angeles County, California. The first portion of the project began operations in December 2012, with six additional blocks coming online in 2013 and an expectation of full commercial operation in the first half of 2014. Generation's estimated remaining commitment for the project is $180 million. | ||||||||||||||||||||||||||
On July 3, 2013, Generation executed a Turbine Supply Agreement to expand its Beebe wind project in Michigan. The estimated remaining commitment under the contract is $52 million and achievement of commercial operations is expected in 2014. | ||||||||||||||||||||||||||
On July 26, 2013, Generation executed an engineering procurement and construction contract to expand its Perryman, Maryland generation site with 120MW of new natural gas-fired generation to satisfy certain merger commitments. The estimated remaining commitment under the contract is $80 million and achievement of commercial operation is expected in 2015. See Note 4 – Mergers and Acquisitions for additional information on commitments to develop or assist in development of new generation in Maryland resulting from the merger. | ||||||||||||||||||||||||||
Refer to Note 3 – Regulatory Matters of the Exelon 2012 Form 10-K for information on investment programs associated with regulatory mandates, such as ComEd's Infrastructure Investment Plan under EIMA, PECO's Smart Meter Procurement and Installation Plan and BGE's comprehensive smart grid initiative. | ||||||||||||||||||||||||||
Constellation Merger Commitments | ||||||||||||||||||||||||||
In December 2011, Exelon and Constellation reached a settlement with the State of Maryland and the City of Baltimore and other interested parties in connection with the regulatory proceedings related to the merger that was pending before the MDPSC. As part of this settlement and the application for approval of the merger by MDPSC, 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 more than $1 billion. | ||||||||||||||||||||||||||
On February 17, 2012, the MDPSC approved the merger with conditions. Many of the conditions were reflective of the settlement agreements described above. 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. See Note 4 – Merger and Acquisitions of the Exelon 2012 Form 10-K for additional information on the merger. | ||||||||||||||||||||||||||
Description | Payment Period | BGE | Generation | Exelon | Statement of Operations Location | |||||||||||||||||||||
BGE rate credit of $100 per residential customer (a) | Q2 2012 | $ | 113 | $ | 0 | $ | 113 | Revenues | ||||||||||||||||||
Customer investment fund to invest in energy efficiency | ||||||||||||||||||||||||||
and low-income energy assistance to BGE customers | 2012 to 2014 | 0 | 0 | 113.5 | O&M Expense | |||||||||||||||||||||
Contribution for renewable energy, energy efficiency | ||||||||||||||||||||||||||
or related projects in Baltimore | 2012 to 2014 | 0 | 0 | 2 | O&M Expense | |||||||||||||||||||||
Charitable contributions at $7 million per year for 10 years | 2012 to 2021 | 28 | 35 | 70 | O&M Expense | |||||||||||||||||||||
State funding for offshore wind development projects | Q2 2012 | 0 | 0 | 32 | O&M Expense | |||||||||||||||||||||
Miscellaneous tax benefits | Q2 2012 | -2 | 0 | -2 | Taxes Other Than Income | |||||||||||||||||||||
Total | $ | 139 | $ | 35 | $ | 328.5 | ||||||||||||||||||||
____________________ | ||||||||||||||||||||||||||
(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. | ||||||||||||||||||||||||||
Contingencies | ||||||||||||||||||||||||||
Commercial Commitments | ||||||||||||||||||||||||||
The Registrants' commercial commitments as of September 30, 2013, representing commitments potentially triggered by future events were as follows: | ||||||||||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||||||||
Letters of credit (non-debt) (a) | $ | 1,514 | $ | 1,463 | $ | 26 | $ | 22 | $ | 1 | ||||||||||||||||
Guarantees | 4,908 | (b) | 1,271 | (c) | 209 | (d) | 181 | (e) | 252 | (f) | ||||||||||||||||
Nuclear insurance premiums (g) | 3,096 | 3,096 | 0 | 0 | 0 | |||||||||||||||||||||
Total commercial commitments | $ | 9,518 | $ | 5,830 | $ | 235 | $ | 203 | $ | 253 | ||||||||||||||||
(a) Non-debt letters of credit maintained to provide credit support for certain transactions as requested by third parties. | ||||||||||||||||||||||||||
(b) Primarily reflects parental guarantees issued on behalf of Generation to allow the flexibility needed to conduct business with counterparties without having to post other forms of collateral. Also reflects guarantees issued to ensure performance under specific contracts, preferred securities of financing trusts, property leases, indemnifications, NRC minimum funding assurance requirements and $211 million on behalf of CENG nuclear generating facilities for credit support and miscellaneous guarantees. The estimated net exposure for obligations under commercial transactions covered by these guarantees was $0.6 billion at September 30, 2013, which represents the total amount Exelon could be required to fund based on September 30, 2013 market prices. | ||||||||||||||||||||||||||
(c) Primarily reflects guarantees issued to ensure performance under energy marketing and other specific contracts and $211 million on behalf of CENG nuclear generating facilities for credit support. The estimated net exposure for obligations under commercial transactions covered by these guarantees was $0.2 billion at September 30, 2013, which represents the total amount Generation could be required to fund based on September 30, 2013 market prices. | ||||||||||||||||||||||||||
(d) Primarily reflects full and unconditional guarantees of $200 million Trust Preferred Securities of ComEd Financing III, which is a 100% owned finance subsidiary of ComEd. | ||||||||||||||||||||||||||
(e) Primarily reflects full and unconditional guarantees of $178 million Trust Preferred Securities of PECO Trust III and IV, which are 100% owned finance subsidiaries of PECO. | ||||||||||||||||||||||||||
(f) Primarily reflects full and unconditional guarantees of $250 million Trust Preferred Securities of BGE Capital Trust II, which is a 100% owned finance subsidiary of BGE. | ||||||||||||||||||||||||||
(g) 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. | ||||||||||||||||||||||||||
Nuclear Insurance (Exelon and Generation) | ||||||||||||||||||||||||||
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 September 30, 2013, the current liability limit per incident was $13.6 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. An inflation adjustment must be made at least once every 5 years and the last inflation adjustment was made effective September 10, 2013. In accordance with the Price-Anderson Act, Generation maintains financial protection at levels equal to the amount of liability insurance available from private sources through the purchase of private nuclear energy liability insurance for public liability claims that could arise in the event of an incident. As of September 30, 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 $2.8 billion. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $13.6 billion limit for a single incident. | ||||||||||||||||||||||||||
Additionally, Generation is also 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. Premiums paid to NEIL by its members are subject to assessment for adverse loss experience (the retrospective premium obligation). The maximum combined retrospective premium amount that Generation could be required to pay due to participation in the Price-Anderson Act retrospective rating plan for power reactors and the NEIL retrospective premium obligation is $3.1 billion, which is included above in the Commercial Commitments table. See the Nuclear Insurance section within Note 19 – Commitments and Contingencies of the Exelon 2012 Form 10-K for additional details on Generation's nuclear insurance premiums. | ||||||||||||||||||||||||||
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 September 30, 2013. Generation believes that it is remote that it will be required to make any additional payments under the guarantee, and currently has no recorded liabilities associated with this guarantee. Generation expects that the exposure covered by this guarantee will expire in 2014. The guarantee is included above in the Commercial Commitments table under guarantees. | ||||||||||||||||||||||||||
Indemnifications Related to Sale of TEG and TEP (Exelon and Generation) | ||||||||||||||||||||||||||
On February 9, 2007, Tamuin International Inc. (TII), a wholly owned subsidiary of Generation, sold its 49.5% ownership interests in TEG and TEP to a subsidiary of AES Corporation for $95 million in cash plus certain purchase price adjustments. In connection with the transaction, Generation entered into a guarantee agreement under which Generation guaranteed the timely payment of TII's obligations to the subsidiary of AES Corporation pursuant to the terms of the purchase and sale agreement relating to the sale of TII's ownership interests. Generation was required to perform in the event that TII did not pay any obligation covered by the guarantee that was not otherwise subject to a dispute resolution process. Portions of the exposures covered by this guarantee expired in 2008, and the remaining guarantee expired in the third quarter of 2013. Generation was not required to make payments under the guarantee, and therefore, has no further obligation related to this guarantee as of September 30, 2013. | ||||||||||||||||||||||||||
Environmental Issues | ||||||||||||||||||||||||||
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, ComEd, PECO or BGE is one of several PRPs that may be responsible for ultimate remediation of each location. | ||||||||||||||||||||||||||
ComEd has identified 42 sites, 16 of which have been approved for cleanup by the Illinois EPA or the U.S. EPA and 26 that are currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these sites to continue through at least 2016. | ||||||||||||||||||||||||||
PECO has identified 26 sites, 16 of which have been approved for cleanup by the PA DEP and 10 that are currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 2020. | ||||||||||||||||||||||||||
BGE has identified 13 former gas manufacturing or purification sites that it currently owns or owned at one time through a predecessor's acquisition. Two gas manufacturing sites require some level of remediation and ongoing monitoring under the direction of the MDE. The required costs at these two sites are not considered material. One gas purification site is in the initial stages of investigation at the direction of the MDE. | ||||||||||||||||||||||||||
ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, are currently recovering environmental remediation costs of former MGP facility sites through customer rates. BGE is authorized to and is currently recovering environmental costs for the remediation of former MGP facility sites from customers; however, while BGE does not have a rider for MGP clean-up costs, BGE has historically received recovery of actual clean-up costs in distribution rates. ComEd, PECO and BGE have recorded regulatory assets for the recovery of these costs. During the third quarter of 2013, ComEd and PECO completed an annual study of their future estimated MGP remediation requirements. The results of these studies indicated that additional remediation would be required at certain sites; accordingly, ComEd and PECO increased their reserves and regulatory assets by less than $1 million and $6 million, respectively. See Note 5 - Regulatory Matters for additional information regarding the associated regulatory assets. | ||||||||||||||||||||||||||
As of September 30, 2013 and December 31, 2012, the Registrants had 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: | ||||||||||||||||||||||||||
30-Sep-13 | Total Environmental Investigation and Remediation Reserve | Portion of Total Related to MGP Investigation and Remediation | ||||||||||||||||||||||||
Exelon | $ | 345 | $ | 280 | ||||||||||||||||||||||
Generation | 56 | 0 | ||||||||||||||||||||||||
ComEd | 237 | 232 | ||||||||||||||||||||||||
PECO | 51 | 48 | ||||||||||||||||||||||||
BGE | 1 | 0 | ||||||||||||||||||||||||
31-Dec-12 | Total Environmental Investigation and Remediation Reserve | Portion of Total Related to MGP Investigation and Remediation | ||||||||||||||||||||||||
Exelon | $ | 351 | $ | 298 | ||||||||||||||||||||||
Generation | 42 | 0 | ||||||||||||||||||||||||
ComEd | 261 | 254 | ||||||||||||||||||||||||
PECO | 47 | 44 | ||||||||||||||||||||||||
BGE | 1 | 0 | ||||||||||||||||||||||||
The Registrants cannot reasonably estimate whether they will incur other significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies or others, or whether such costs will be recoverable from third parties, including customers. | ||||||||||||||||||||||||||
Water Quality | ||||||||||||||||||||||||||
Section 316(b) of the Clean Water Act. Section 316(b) requires that the cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts, and is implemented through state-level NPDES permit programs. All of Generation's and CENG's power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems (e.g., cooling towers) are potentially most affected. For Generation, those facilities are Clinton, Dresden, Eddystone, Fairless Hills, Gould Street, Handley, Mountain Creek, Mystic 7, Oyster Creek, Peach Bottom, Quad Cities, Riverside, Salem and Schuylkill. For CENG, those facilities are Calvert Cliffs, Nine Mile Point Unit 1 and R.E. Ginna. | ||||||||||||||||||||||||||
On March 28, 2011, the U.S. EPA issued the proposed regulation under Section 316(b). The proposal does not require closed-cycle cooling (e.g., cooling towers) as the best technology available to address impingement and entrainment. The proposal provides the state permitting agency with discretion to determine the best technology available to limit entrainment (drawing aquatic life into the plants cooling system) mortality, including application of a cost-benefit test and the consideration of a number of site-specific factors. After consideration of these factors, the state permitting agency may require closed cycle cooling, an alternate technology, or determine that the current technology is the best available. The proposed rule also imposes limits on impingement (trapping aquatic life on screens) mortality, which likely will be accomplished by the installation of screens or another technology at the intake. Exelon filed comments on the proposed regulation on August 18, 2011, stating its support for a number of its provisions (e.g., cooling towers not required as best technology available, and the use of site-specific and cost benefit analysis) while also noting a number of technical provisions that require revision to take into account existing unit operations and practices within the industry. | ||||||||||||||||||||||||||
In June 2012, the U.S. EPA published two Notices of Data Availability (NODA) seeking public comment on alternate compliance technologies for impingement and the use of a public opinion survey to calculate the so-called “non-use” benefits of the rule. Exelon filed comments for each NODA, supporting the additional flexibility afforded by the impingement NODA, and opposing the NODA relating to calculation of non-use benefits due to its inaccurate and unreliable methodologies that would artificially inflate the benefits of proposed technologies that would otherwise not be cost-effective. On June 27, 2013, the U.S. EPA agreed to amend the court approved Settlement Agreement to extend the deadline to issue a final rule until November 4, 2013; on October 30, 2013 the Agency invoked the force majeure provision of the Settlement Agreement to extend the final rule deadline until November 20, 2013 due to the early October 2013 federal government shutdown. Until the rule is finalized, the state permitting agencies will continue to apply their best professional judgment to address impingement and entrainment. | ||||||||||||||||||||||||||
Salem and Other Power Generation Facilities. In June 2001, the NJDEP issued a renewed NPDES permit for Salem, allowing for the continued operation of Salem with its existing cooling water system. NJDEP advised PSEG, in July 2004 that it strongly recommended reducing cooling water intake flow commensurate with closed-cycle cooling as a compliance option for Salem. PSEG submitted an application for a renewal of the permit on February 1, 2006. In the permit renewal application, PSEG analyzed closed-cycle cooling and other options and demonstrated that the continuation of the Estuary Enhancement Program, an extensive environmental restoration program at Salem, is the best technology to meet the Section 316(b) requirements. PSEG continues to operate Salem under the approved June 2001 NPDES permit while the NPDES permit renewal application is being reviewed. If the final permit or Section 316(b) regulations ultimately requires the retrofitting of Salem's cooling water intake structure to reduce cooling water intake flow commensurate with closed-cycle cooling, Exelon's and Generation's share of the total cost of the retrofit and any resulting interim replacement power would likely be in excess of $430 million, based on a 2006 estimate, and would result in increased depreciation expense related to the retrofit investment. | ||||||||||||||||||||||||||
It is unknown at this time whether the NJDEP permit programs will require closed-cycle cooling at Salem. In addition, the economic viability of Generation's other power generation facilities, as well as CENG's, without closed-cycle cooling water systems will be called into question by any requirement to construct cooling towers. Should the final rule not require the installation of cooling towers, and retain the flexibility afforded the state permitting agencies in applying a cost benefit test and to consider site-specific factors, the impact of the rule would be minimized even though the costs of compliance could be material to Generation and CENG. | ||||||||||||||||||||||||||
Given the uncertainties associated with the requirements that will be contained in the final rule, Generation cannot predict the eventual outcome or estimate the effect that compliance with any resulting Section 316(b) or interim state requirements will have on the operation of its and CENG's generating facilities and its future results of operations, cash flows and financial position. | ||||||||||||||||||||||||||
Groundwater Contamination. In October 2007, a subsidiary of Constellation entered into a consent decree with the MDE relating to groundwater contamination at a third-party facility that was licensed to accept fly ash, a byproduct generated by coal-fired plants. The consent decree required the payment of a $1 million penalty, remediation of groundwater contamination resulting from the ash placement operations at the site, replacement of drinking water supplies in the vicinity of the site, and monitoring of groundwater conditions. Prior to the Merger, Constellation recorded in its Consolidated Balance Sheets total liabilities of approximately $30 million to comply with the consent decree with an additional $3 million recognized through purchase accounting. During the three months ended September 30, 2013, Generation increased its reserve by $2 million based on an update of future estimated remediation costs. The remaining liability as of September 30, 2013, is approximately $15 million. In addition, a private party has asserted claims relating to groundwater contamination. Generation believes that these claims are without merit and is vigorously contesting them. As of September 30, 2013, Generation believes that it is remote that it will be required to make payments under these private party claims. | ||||||||||||||||||||||||||
Air Quality | ||||||||||||||||||||||||||
Cross State Air Pollution Rule (CSAPR). On July 11, 2008, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) vacated the CAIR, which had been promulgated by the U.S. EPA to reduce power plant emissions of SO2 and NOx. The D.C. Circuit Court later remanded the CAIR to the U.S. EPA, without invalidating the entire rulemaking, so that the U.S. EPA could correct CAIR in accordance with the D.C. Circuit Court's July 11, 2008 opinion. On July 7, 2011, the U.S. EPA published the final rule, known as the CSAPR. The CSAPR requires 28 states in the eastern half of the United States to significantly improve air quality by reducing power plant emissions that cross state lines and contribute to ground-level ozone and fine particle pollution in other states. | ||||||||||||||||||||||||||
Numerous entities challenged the CSAPR in the D.C. Circuit Court, and some requested a stay of the rule pending the Court's consideration of the matter on the merits. On December 30, 2011, the Court granted a stay of the CSAPR, and directed the U.S. EPA to continue the administration of CAIR in the interim. On August 21, 2012, a three-judge panel of the D.C. Circuit Court held that the U.S. EPA has exceeded its authority in certain material aspects of the CSAPR and vacated the rule and remanded it to the U.S. EPA for further rulemaking consistent with its decision. The Court also ordered that CAIR remain in effect pending finalization of CSAPR on remand. On January 24, 2013, the Court denied petitions for reconsideration of the ruling by the three-judge panel. In June 2013, the U.S. Supreme Court granted the U.S. EPA's petition to review the D.C. Circuit Court's CSAPR decision. Oral argument has been scheduled for December 10, 2013. | ||||||||||||||||||||||||||
Under the CSAPR, generation units were to receive allowances based on historic heat input and intrastate, and limited interstate, trading of allowances was permitted. The CSAPR restricted entirely the use of pre-2012 allowances. Existing SO2 allowances under the ARP would remain available for use under ARP. As of September 30, 2013, Generation had $64 million of emission allowances carried at the lower of weighted average cost or market. | ||||||||||||||||||||||||||
EPA Mercury and Air Toxics Standards (MATS). The MATS rule became final on April 16, 2012. The MATS rule reduces emissions of toxic air pollutants, and finalized the new source performance standards for fossil fuel-fired electric utility steam generating units (EGUs). The MATS rule requires coal-fired EGUs to achieve high removal rates of mercury, acid gases and other metals from air emissions. To achieve these standards, coal units with no pollution control equipment installed (uncontrolled coal units) will have to make capital investments and incur higher operating expenses. It is expected that smaller, older, uncontrolled coal units will retire rather than make these investments. Coal units with existing controls that do not meet the required standards may need to upgrade existing controls or add new controls to comply. In addition, the new standards will require oil units to achieve high removal rates of metals. Owners of oil units not currently meeting the proposed emission standards may choose to convert the units to light oils or natural gas, install control technologies or retire the units. The MATS rule requires generating stations to meet the new standards three years after the rule takes effect, April 16, 2015, with specific guidelines for an additional one or two years in limited cases. Numerous entities have challenged MATS in the D.C. Circuit Court, and Exelon was granted permission by the Court to intervene in support of the rule. A decision by the Court will not occur until 2014. The outcome of the appeal, and its impact on power plant operators' investment and retirement decisions, is uncertain. | ||||||||||||||||||||||||||
Exelon, along with the other co-owners of Conemaugh Generating Station are moving forward with plans to improve the existing scrubbers and install Selective Catalytic Reduction (SCR) controls to meet the mercury removal requirements of MATS. | ||||||||||||||||||||||||||
In addition, as of September 30, 2013, Exelon had a $691 million net investment in coal-fired plants in Georgia and Texas subject to long-term leases extending through 2028-2032. While Exelon currently estimates the value of these plants at the end of the lease term will be in excess of the recorded residual lease values, after the impairment recorded in the second quarter of 2013, final applications of the CSAPR and MATS regulations could negatively impact the end-of-lease term values of these assets, which could result in a future impairment loss that could be material. See Note 7 – Impairment of Long-Lived Assets for additional information. | ||||||||||||||||||||||||||
National Ambient Air Quality Standards (NAAQS). The U.S. EPA previously announced that it would complete a review of all NAAQS by 2014. Oral argument in the litigation (State of Miss. v. EPA) of the final 2008 ozone standard occurred in the D.C. Circuit Court in November 2012 and a final Court decision was issued on July 23, 2013 with the 2008 primary ozone standard upheld, but the secondary standard remanded to EPA for reconsideration. Concurrent with litigation of the 2008 ozone standard, the U.S. EPA continues its regular, periodic review of the ozone NAAQS and is expected to propose revisions in the fall of 2014, with preliminary indications that the U.S. EPA will likely propose a tightened standard. It is unclear at this point in time whether the U.S. EPA will be able to respond to the Court remand of the secondary 2008 ozone standard on a timeframe that would be any quicker than that of the U.S. EPA's current, periodic review schedule. In December 2012, the U.S. EPA issued its final revisions to the Agency's particulate matter (PM) NAAQS. In its final rule, the U.S. EPA lowered the annual PM2.5 standard, but declined to issue a new secondary NAAQS to improve urban visibility. The U.S. EPA indicated in its final rule that by 2020 it expects most areas of the country will be in attainment of the new PM2.5 NAAQS based on currently expected regulations, such as the MATS regulation. It is unclear if the vacatur of the CSAPR, one of the regulations that the U.S. EPA is relying on to assist with future PM reduction, would alter the U.S. EPA's view since either CAIR or a finalized CSAPR regulation would be in effect leading up to 2020. In March 2013, a number of industry coalitions filed a joint lawsuit challenging the new PM2.5 standard. Also during early 2013, the D.C. Circuit remanded several rules for implementation of earlier PM2.5 NAAQS to the U.S. EPA for revision of certain aspects of the rules, with a requirement that the U.S. EPA re-promulgate regulations in conformance with the correct subparts of the Clean Air Act. | ||||||||||||||||||||||||||
In addition to these NAAQS, the U.S. EPA also finalized nonattainment designations for certain areas in the United States for the 2010 one-hour SO2 standard on August 5, 2013, and indicated that additional nonattainment areas will be designated in a future rulemaking. EPA will require states to submit state implementation plans (SIPs) for nonattainment areas by April 2015. With regard to Texas and Maryland, no nonattainment areas were identified in EPA's final designation rule. With regard to Illinois and Pennsylvania, several counties, or portions of counties, in each state were identified as nonattainment. The U.S. EPA will follow the approach outlined in a February 2013 EPA strategy document that establishes a process and timeline for the Agency to address additional designations in states' counties under a future rulemaking. Nonattainment county compliance with the one-hour SO2 standard is required by October 2018. While significant SO2 reductions will occur as a result of MATS compliance in 2015, Exelon is unable to predict the requirements of pending states' SIPs to further reduce SO2 emissions in support of attainment of the one hour SO2 standard. | ||||||||||||||||||||||||||
Notices and Finding of Violations and Midwest Generation Bankruptcy. In December 1999, ComEd sold several generating stations to Midwest Generation, LLC (Midwest Generation), a subsidiary of Edison Mission Energy (EME). Under the terms of the sale agreement, Midwest Generation and EME assumed responsibility for environmental liabilities associated with the ownership, occupancy, use and operation of the stations, including responsibility for compliance by the stations with environmental laws before their purchase by Midwest Generation. Midwest Generation and EME additionally agreed to indemnify and hold ComEd and its affiliates harmless from claims, fines, penalties, liabilities and expenses arising from third party claims against ComEd resulting from or arising out of the environmental liabilities assumed by Midwest Generation and EME under the terms of the agreement governing the sale. In connection with Exelon's 2001 corporate restructuring, Generation assumed ComEd's rights and obligations with respect to its former generation business, including its rights and obligations under the sale agreement with Midwest Generation and EME. | ||||||||||||||||||||||||||
On August 6, 2007, ComEd received a NOV addressed to it and Midwest Generation from the U.S. EPA, alleging, in relevant part, that ComEd and Midwest Generation violated and are continuing to violate provisions of the Clean Air Act as a result of the modification and/or operation of six electric generation stations located in northern Illinois that have been owned and operated by Midwest Generation since their purchase from ComEd in 1999. In August 2009, the United States and the State of Illinois filed a complaint against Midwest Generation with the U.S. District Court for the Northern District of Illinois initiating enforcement proceedings with respect to most of the alleged Clean Air Act violations set forth in the NOV. Neither ComEd nor Exelon was named as a defendant in this original complaint. In March 2010, the District Court granted Midwest Generation's partial motion to dismiss all but one of the claims against Midwest Generation. The District Court held that Midwest Generation cannot be liable for any alleged violations relating to construction that occurred prior to Midwest Generation's ownership of the stations. In May 2010, the government plaintiffs filed an amended complaint against Midwest Generation asserting claims substantially similar to those in the original complaint, and added ComEd and EME as defendants. The amended complaint seeks injunctive relief and civil penalties against all defendants, although not all of the claims specifically pertain to ComEd. On March 16, 2011, the District Court granted ComEd's motion to dismiss the May 2010 complaint in its entirety as it relates to ComEd. On January 3, 2012, upon leave of the District Court, the government parties appealed the dismissal of ComEd to the U.S. Circuit Court of Appeals for the Seventh Circuit. On July 8, 2013, the Circuit Court affirmed the District Court's dismissal of the complaint against ComEd. On September 19, 2013, the Circuit Court denied the petition for a rehearing filed by the governmental parties. Exelon, Generation and ComEd have concluded that, in light of the Circuit Court decision, the likelihood of loss is remote. Therefore, no reserve has been established. | ||||||||||||||||||||||||||
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. | ||||||||||||||||||||||||||
The Bankruptcy Court approved the rejection of a coal rail car lease under which Midwest Generation had agreed to reimburse ComEd for all obligations. The rejection left Generation as the party responsible to make remaining payments under the lease. In January 2013, Generation made the final $10 million payment due under the lease agreement which had been reserved for at December 31, 2012. As a result of the bankruptcy filing, Exelon and Generation have recorded liabilities as of September 30, 2013 of $3 million for estimated payments for asbestos personal injury claims filed pre-Petition Date. Exelon and Generation currently expect Midwest Generation or its successor will remain responsible for asbestos personal injury claims filed post-Petition Date, and as such have recorded no liability for such amounts. Requirements for Generation to ultimately satisfy such claims could have a material adverse impact on Exelon's and Generation's future results of operations. During the second quarter of 2013, ComEd filed proofs of claim of $21 million with the Bankruptcy Court for amounts owed by EME and Midwest Generation for the coal rail car lease, ComEd utility payments and certain legal costs. As of September 30, 2013, Exelon and ComEd have not recorded a receivable for the filed proofs of claim because recovery of such amount cannot be assured at this point in the bankruptcy. Exelon and ComEd will not record financial benefits associated with claim recoveries until realized. | ||||||||||||||||||||||||||
As of the Petition Date, Generation had wholesale power transactions with Edison Mission Marketing and Trading, an affiliate of Midwest Generation not included in the bankruptcy proceeding. Generation expects these transactions to be fully settled in the normal course. | ||||||||||||||||||||||||||
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 the 2001 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 requiring remediation, with the determination of the allocation among the parties subject to many uncertain factors, including the impact of Midwest Generation's bankruptcy. Additionally, the obligations of EME and Midwest Generation to ComEd under the sale agreement, including the environmental indemnity, may be discharged in the bankruptcy proceeding. In such circumstances, ComEd (and Generation, through ComEd) may only have an unsecured claim against EME and Midwest Generation for the environmental remediation costs that would have otherwise been obligations of EME and Midwest Generation under the sale agreement. This unsecured claim may yield a fractional, or possibly no, recovery for ComEd and Generation. | ||||||||||||||||||||||||||
On October 18, 2013, NRG Energy entered into an agreement to buy EME's portfolio of generation. EME may continue to solicit alternative transaction proposals from third parties through December 6, 2013. Any such transaction would require the approval of the U.S. Bankruptcy Court. ComEd and Generation are currently evaluating the terms of the agreements to determine the impact they could have on the bankruptcy proceedings and ComEd's and Generation's claims. | ||||||||||||||||||||||||||
ComEd and Generation continue to monitor the bankruptcy proceedings and available public information as to potential environmental exposures regarding the Midwest Generation plant sites. Midwest Generation publicly disclosed in its quarter ending June 30, 2013 Form 10-Q that (i) it has accrued a probable amount of approximately $8 million for estimated environmental investigation and remediation costs under CERCLA, or similar laws, for the investigation and remediation of contaminated property at four Midwest Generation plant sites, (ii) it has identified stations for which a reasonable estimate for investigation and/ or remediation cannot be made and (iii) it and the Illinois EPA entered into Compliance Commitment Agreements outlining specified environmental remediation measures and groundwater monitoring activities to be undertaken at its Crawford, Powerton, Joliet, Will County and Waukegan generating stations. At this time, however, ComEd and Generation do not have sufficient information to reasonably assess the potential likelihood or magnitude of any such exposures. Further, Midwest Generation's bankruptcy process will likely extend into mid-2014, and unless there is a successful transaction involving NRG Energy, the outcome is uncertain, including whether the facilities will continue to operate and the identity or financial wherewithal of potential future plant owners. 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 no liability has been recorded as of September 30, 2013. Any liability imposed on ComEd or Generation for environmental matters relating to the generating stations could have a material adverse impact on their future results of operations and cash flows. | ||||||||||||||||||||||||||
Solid and Hazardous Waste | ||||||||||||||||||||||||||
Cotter Corporation. The U.S. EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. On February 18, 2000, ComEd sold Cotter to an unaffiliated third party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising in connection with the West Lake Landfill. In connection with Exelon's 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. On May 29, 2008, the U.S. EPA issued a Record of Decision approving the remediation option submitted by Cotter and the two other PRPs that required additional landfill cover. The current estimated cost of the anticipated landfill cover remediation for the site is approximately $42 million, which will be allocated among all PRPs. Generation has accrued what it believes to be an adequate amount to cover its anticipated share of such liability. By letter dated January 11, 2010, the U.S. EPA requested that the PRPs perform a supplemental feasibility study for a remediation alternative that would involve complete excavation of the radiological contamination. On September 30, 2011, the PRPs submitted the final supplemental feasibility study to the U.S. EPA for review. In June 2012, the U.S. EPA requested that the PRPs perform additional analysis and groundwater sampling as part of the supplemental feasibility study that could take up to one year to complete, and subsequently requested additional analysis sampling and modeling to be conducted in 2013 and 2014. In light of these additional requests, it is unknown when the U.S EPA will propose a remedy for public comment. Thereafter the U.S. EPA will select a final remedy and enter into a Consent Decree with the PRPs to effectuate the remedy. A complete excavation remedy would be significantly more expensive than the previously selected additional cover remedy; however, Generation believes the likelihood that the U.S. EPA would require a complete excavation remedy is remote. | ||||||||||||||||||||||||||
On August 8, 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government's clean-up costs for contamination attributable to low level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri. The Latty Avenue site is included in ComEd's indemnification responsibilities discussed above as part of the sale of Cotter. The radioactive residues had been generated initially in connection with the processing of uranium ores as part of the U.S. government's Manhattan Project. Cotter purchased the residues in 1969 for initial processing at the Latty Avenue facility for the subsequent extraction of uranium and metals. In 1976, the NRC found that the Latty Avenue site had radiation levels exceeding NRC criteria for decontamination of land areas. Latty Avenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under the Formerly Utilized Sites Remedial Action Program. The DOJ has not yet formally advised the PRPs of the amount that it is seeking, but it is believed to be approximately $90 million. The DOJ and the PRPs agreed to toll the statute of limitations until August 2014 so that settlement discussions could proceed. Based on Exelon's preliminary review, it appears probable that Exelon has liability to Cotter under the indemnification agreement and has established an appropriate accrual for this liability. | ||||||||||||||||||||||||||
On February 28, 2012, and April 12, 2012, two lawsuits were filed in the U.S. District Court for the Eastern District of Missouri against 15 and 14 defendants, respectively, including Exelon, Generation and ComEd (the “Exelon defendants”) and Cotter. The suits allege that individuals living in the North St. Louis area developed some form of cancer due to the defendants' negligent or reckless conduct in processing, transporting, storing, handling and/or disposing of radioactive materials. Plaintiffs have asserted claims for negligence, strict liability, emotional distress, medical monitoring, and violations of the Price−Anderson Act. The complaints do not contain specific damage claims. On May 30, 2012, the plaintiffs filed voluntary motions to dismiss the Exelon defendants from both lawsuits which were subsequently granted. On October 23, 2012, a third lawsuit was filed in the same court on behalf of three additional plaintiffs against Cotter and seven other defendants, but not Exelon. On April 19, 2013, a fourth lawsuit was filed in the same court on behalf of two additional plaintiffs against Cotter and seven other defendants, but not Exelon. On June 18, 2013, a fifth lawsuit was filed in the same court on behalf of one plaintiff against eight defendants, including Cotter but not Exelon. On July 31, 2013, a sixth lawsuit was filed in the same court on behalf of two plaintiffs against Cotter and four other defendants, but not Exelon. The allegations in these latter four complaints mirror the initially filed lawsuits. In the event of a finding of liability, it is reasonably possible that Exelon would be considered liable due to its indemnification responsibilities of Cotter described above. On March 27, 2013, the U.S. District Court dismissed all state common law actions brought under the initial two lawsuits; and also found that the plaintiffs had not properly brought the actions under the Price–Anderson Act. On July 8, 2013, the plaintiffs filed amended complaints under the Price–Anderson Act. Cotter moved to dismiss the amended complaints and has motions currently pending before the court. At this stage of the litigation, Exelon cannot estimate a range of loss, if any. | ||||||||||||||||||||||||||
68th Street Dump. In 1999, the U.S. EPA proposed to add the 68th Street Dump in Baltimore, Maryland to the Superfund National Priorities List, and notified BGE and 19 others that they are PRPs at the site. In March 2004, BGE and other PRPs formed the 68th Street Coalition and entered into consent order negotiations with the U.S. EPA to investigate clean-up options for the site under the Superfund Alternative Sites Program. In May 2006, a settlement among the U.S. EPA and 19 of the PRPs, including BGE, with respect to investigation of the site became effective. The settlement requires the PRPs, over the course of several years, to identify contamination at the site and recommend clean-up options. The potentially responsible parties 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, EPA issued its Record of Decision specifying the remedies to be implemented at the site based on the information and recommendations of the PRP investigation. The costs to implement these remedies are still expected to be in the range of $50 million to $64 million. The U.S. EPA is expected to make a final selection of one of the alternatives in 2013. Based on Exelon's preliminary review, it appears probable that Exelon has liability and has established an appropriate accrual for its share of the estimated clean-up costs. BGE is indemnified by a wholly owned subsidiary of Generation for most of the costs related to this settlement and clean-up of the site. | ||||||||||||||||||||||||||
Rossville Ash Site. The Rossville Ash Site is a 32-acre property located in Rosedale, Baltimore County, MD. which was used for the placement of fly ash from 1983-2007. The property is owned by Constellation Power Source Generation, Inc.(CPSG). In 2008, CPSG investigated and remediated the property by entering it into the MD 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. We currently estimate the cost to close the site to be approximately $6 million. | ||||||||||||||||||||||||||
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, MD. The U.S. EPA offered BGE and three other PRPs the opportunity to conduct an environmental investigation and present cleanup recommendations at the site. In addition, the U.S. EPA is seeking recovery from the PRPs of $1.7 million for past cleanup and investigation costs at the site. On March 11, 2013, BGE and three other PRP's signed an Administrative Settlement Agreement and Order on Consent with the U.S. EPA which requires the PRP's to conduct a Remedial Investigation and Feasibility Study at the site to determine what, if any, are the appropriate and recommended cleanup activities for the site. The ultimate outcome of this proceeding is uncertain. Since the U.S. EPA has not selected a cleanup remedy and the allocation of the cleanup costs among the PRPs has not been determined, an estimate of the range of BGE's reasonably possible loss, if any, cannot be determined. | ||||||||||||||||||||||||||
Climate Change Regulation. Exelon is subject to climate change regulation or legislation at the Federal, regional and state levels. In 2007, the U.S. Supreme Court ruled that GHG emissions are pollutants subject to regulation under the new motor vehicle provisions of the Clean Air Act. Consequently, on December 7, 2009, the U.S. EPA issued an endangerment finding under Section 202 of the Clean Air Act regarding GHGs from new motor vehicles and on April 1, 2010 issued final regulations limiting GHG emissions from cars and light trucks effective on January 2, 2011. While such regulations do not specifically address stationary sources, such as a generating plant, it is the U.S. EPA's position that the regulation of GHGs under the mobile source provisions of the Clean Air Act has triggered the permitting requirements under the Prevention of Significant Deterioration (PSD) and Title V operating permit sections of the Clean Air Act for new and modified stationary sources effective January 2, 2011. Therefore, on May 13, 2010, the U.S. EPA issued final regulations (the Tailoring Rule) relating to these provisions of the Clean Air Act for major stationary sources of GHG emissions that apply to new sources that emit greater than 100,000 tons per year, on a CO2 equivalent basis, and to modifications to existing sources that result in emissions increases greater than 75,000 tons per year on a CO2 equivalent basis. These thresholds became effective January 2, 2011, apply for six years and will be reviewed by the U.S. EPA for future applicability thereafter. On July 2, 2012 the U.S. EPA declined to lower GHG permit thresholds in its final “Step 3” Tailoring Rule update. The U.S. EPA will review permit thresholds again in a 2015 rulemaking process. On June 26, 2012, the United States Court of Appeals for the District of Columbia, in a per curium decision, dismissed industry and state petitions challenging the U.S. EPA's “Tailpipe Rule” for cars and light duty trucks, the endangerment finding for GHG's from stationary sources, and the Tailoring Rule. On October 15, 2013 the U.S. Supreme Court granted industry petitions to review one aspect of the PSD permitting regulations. Under the PSD regulations, new and modified major stationary sources could be required to install best available control technology, to be determined on a case by case basis. Generation could be significantly affected by the regulations if it were to build new plants or modify existing plants. | ||||||||||||||||||||||||||
On June 25, 2013, President Obama announced “The President's Climate Action Plan,” a summary of executive branch actions intended to: reduce carbon emissions; prepare the United States for the impacts of climate change; and lead international efforts to combat global climate change and prepare for its impacts. Concurrent with the announcement of the Administration's plan, the President also issued a Memorandum for the Administrator of the Environmental Protection Agency that focused on power generation sector carbon reductions under the Section 111 New Source Performance Standards (NSPS) section of the federal Clean Air Act. The memorandum directs the EPA Administrator to issue two sets of proposed rulemakings with regard to power plant carbon emissions under Section 111 of the Clean Air Act. | ||||||||||||||||||||||||||
The first rulemaking, under Section 111(b) of the Clean Air Act is to focus on establishing carbon regulations for new fossil-fuel power plants. This rulemaking was proposed on September 20, 2013 and is to be finalized “in a timely fashion.” In the proposed rule EPA sets separate standards for fossil-fuel fired utility boilers and natural gas fired stationary combustion turbines. | ||||||||||||||||||||||||||
The second rulemaking, under Section 111(d) of the Clean Air Act is to focus on modified, reconstructed and existing fossil power plants. The rulemaking is to be proposed no later than June 1, 2014, be finalized no later than June 1, 2015, and require that states submit to EPA their implementation plans no later than June 30, 2016. In developing this rulemaking, EPA is directed to consider a number of factors, including options to reduce costs, options to ensure the continued use of a range of energy sources and technologies, options that are consistent with reliable and affordable power, and options that allow for the use of market-based instruments, performance standards and other regulatory flexibilities. | ||||||||||||||||||||||||||
To the extent that the final Section 111(d) rule results in emission reductions from fossil fuel fired plants, and thereby imposes some form of direct or indirect price of carbon in competitive electricity markets, Exelon's overall low carbon generation portfolio results could benefit. | ||||||||||||||||||||||||||
Litigation and Regulatory Matters | ||||||||||||||||||||||||||
Except to the extent noted below, the circumstances set forth in Note 19 of the Exelon 2012 Form 10-K describe, in all material respects, the current status of litigation matters. The following is an update to that discussion. | ||||||||||||||||||||||||||
Asbestos Personal Injury Claims (Exelon, Generation 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 September 30, 2013 and December 31, 2012, Generation had reserved approximately $65 million and $63 million, respectively, in total for asbestos-related bodily injury claims. As of September 30, 2013, approximately $17 million of this amount related to 211 open claims presented to Generation, while the remaining $48 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. | ||||||||||||||||||||||||||
BGE. Since 1993, BGE and certain Constellation subsidiaries (now Generation) have been involved in several actions concerning asbestos. The actions are based upon the theory of "premises liability," alleging that BGE and certain Constellation subsidiaries knew of and exposed individuals to an asbestos hazard. In addition to BGE and certain Constellation subsidiaries, numerous other parties are defendants in these cases. | ||||||||||||||||||||||||||
Approximately 480 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. | ||||||||||||||||||||||||||
Continuous Power Interruption (ComEd) | ||||||||||||||||||||||||||
Section 16-125 of the Illinois Public Utilities Act provides that in the event an electric utility, such as ComEd, experiences a continuous power interruption of four hours or more that affects (in ComEd's case) more than 30,000 customers, the utility may be liable for actual damages suffered by customers as a result of the interruption and may be responsible for reimbursement of local governmental emergency and contingency expenses incurred in connection with the interruption. Recovery of consequential damages is barred. The affected utility may seek from the ICC a waiver of these liabilities when the utility can show that the cause of the interruption was unpreventable damage due to weather events or conditions, customer tampering, or certain other causes enumerated in the law. | ||||||||||||||||||||||||||
On August 18, 2011, ComEd sought from the ICC a determination that ComEd is not liable for damage compensation to customers in connection with the July 11, 2011 storm system that produced multiple power interruptions that in the aggregate affected more than 900,000 customers in ComEd's service territory, as well as for five other storm systems that affected ComEd's customers during June and July 2011 (Summer 2011 Storm Docket). In addition, on September 29, 2011, ComEd sought from the ICC a determination that it was not liable for damage compensation related to the February 1, 2011 blizzard (February 2011 Blizzard Docket). | ||||||||||||||||||||||||||
On June 5, 2013, the ICC approved a complete waiver of liability for five of the six summer storms and the February 2011 blizzard. However, the ICC held that for the July 11, 2011 storm, 34,559 interruptions were preventable and therefore no waiver should apply. As required by the ICC's Order, ComEd will notify relevant customers that they may be entitled to seek reimbursement of incurred costs in accordance with a claims procedure established under ICC rules and regulations. In addition, the ICC found that ComEd did not systematically fail in its duty to provide adequate, reliable and safe service. As a result, the ICC rejected the Illinois Attorney General's request for the ICC to open an investigation into ComEd's infrastructure and storm hardening investments. | ||||||||||||||||||||||||||
Following the ICC's June 26, 2013 denial of ComEd's request for rehearing, on June 27, 2013 ComEd filed an appeal of both the summer and winter storm dockets with the Illinois Appellate Court regarding the ICC's interpretation of Section 16-125 of the Illinois Public Utilities Act. ComEd cannot predict the outcome of appeals. | ||||||||||||||||||||||||||
As a result of the ICC's June 5, 2013 ruling, ComEd established a liability which was not material, for potential reimbursements for actual damages incurred by the 34,559 customers covered by the ICC's June 5, 2013 Order. The liability recorded represents the low end of a range of potential losses given that no amount within the range represents a better estimate. ComEd's ultimate liability will be based on actual claims eligible for reimbursement as well as the outcome of the appeal. Although reimbursements for actual damages will differ from the estimated accrual recorded, at this time ComEd does not expect the difference to be material to ComEd's results of operations or cash flows. | ||||||||||||||||||||||||||
ComEd has not recorded an accrual for reimbursement of local governmental emergency and contingency expenses as a range of loss, if any, cannot be reasonably estimated at this time, but may be material to ComEd's results of operations and cash flows. | ||||||||||||||||||||||||||
Securities Class Action (Exelon) | ||||||||||||||||||||||||||
Three federal securities class action lawsuits were filed in the United States District Courts for the Southern District of New York and the District of Maryland between September 2008 and November 2008 against Constellation. The cases were filed on behalf of a proposed class of persons who acquired publicly traded securities, including the Series A Junior Subordinated Debentures (Debentures), of Constellation between January 30, 2008 and September 16, 2008, and who acquired Debentures in an offering completed in June 2008. The securities class actions generally allege that Constellation, a number of its former officers or directors, and the underwriters violated the securities laws by issuing a false and misleading registration statement and prospectus in connection with Constellation's June 27, 2008 offering of the Debentures. The securities class actions also allege that Constellation issued false or misleading statements or was aware of material undisclosed information which contradicted public statements, including in connection with its announcements of financial results for 2007, the fourth quarter of 2007, the first quarter of 2008 and the second quarter of 2008 and the filing of its first quarter 2008 Form 10-Q. The securities class actions sought, among other things, certification of the cases as class actions, compensatory damages, reasonable costs and expenses, including counsel fees, and rescission damages. | ||||||||||||||||||||||||||
The Southern District of New York granted the defendants' motion to transfer the two securities class actions filed in Maryland to the District of Maryland, and the actions have since been transferred for coordination with the securities class action filed there. On May 9, 2013, the federal court in Maryland preliminarily approved the settlement of Constellation's 2008 Securities Class Action for a payment of $4 million, which will be paid by Constellation's insurer. Notice of the settlement was provided to class members in June, 2013 and opt-outs and objections are due by August 19, 2013 with a final settlement hearing scheduled for November 1, 2013. This settlement will resolve all of Constellation's litigation arising from the 2008 Securities Class Action lawsuit. | ||||||||||||||||||||||||||
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. The Company 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 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 (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||||||||||||
See Note 12 - 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) | 9 Months Ended | |||||||||||||||||
Sep. 30, 2013 | ||||||||||||||||||
Supplemental Financial Information Tables [Line Items] | ' | |||||||||||||||||
Supplemental Financial Information (Exelon, Generation, ComEd, PECO and BGE) | ' | |||||||||||||||||
19. 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 three and nine months ended September 30, 2013 and 2012: | ||||||||||||||||||
Three Months Ended September 30, 2013 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||
Other, Net | ||||||||||||||||||
Decommissioning-related activities: | ||||||||||||||||||
Net realized income on decommissioning trust funds (a) | ||||||||||||||||||
Regulatory agreement units | $ | 138 | $ | 138 | $ | 0 | $ | 0 | $ | 0 | ||||||||
Non-regulatory agreement units | 35 | 35 | 0 | 0 | 0 | |||||||||||||
Net unrealized gains on decommissioning trust funds | ||||||||||||||||||
Regulatory agreement units | 103 | 103 | 0 | 0 | 0 | |||||||||||||
Non-regulatory agreement units | 46 | 46 | 0 | 0 | 0 | |||||||||||||
Net unrealized losses on pledged assets | ||||||||||||||||||
Zion Station decommissioning | -9 | -9 | 0 | 0 | 0 | |||||||||||||
Regulatory offset to decommissioning trust fund-related | ||||||||||||||||||
activities(b) | -189 | -189 | 0 | 0 | 0 | |||||||||||||
Total decommissioning-related activities | 124 | 124 | 0 | 0 | 0 | |||||||||||||
Investment income | 1 | 0 | 0 | 0 | 2 | (c) | ||||||||||||
Long-term lease income | 7 | 0 | 0 | 0 | 0 | |||||||||||||
AFUDC - Equity | 4 | 0 | 2 | 1 | 1 | |||||||||||||
Other | 19 | 10 | 5 | 0 | 1 | |||||||||||||
Other, net | $ | 155 | $ | 134 | $ | 7 | $ | 1 | $ | 4 | ||||||||
Nine Months Ended September 30, 2013 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||
Other, Net | ||||||||||||||||||
Decommissioning-related activities: | ||||||||||||||||||
Net realized income on decommissioning trust funds (a) | ||||||||||||||||||
Regulatory agreement units | $ | 221 | $ | 221 | $ | 0 | $ | 0 | $ | 0 | ||||||||
Non-regulatory agreement units | 65 | 65 | 0 | 0 | 0 | |||||||||||||
Net unrealized gains on decommissioning trust funds | ||||||||||||||||||
Regulatory agreement units | 196 | 196 | 0 | 0 | 0 | |||||||||||||
Non-regulatory agreement units | 70 | 70 | 0 | 0 | 0 | |||||||||||||
Net unrealized losses on pledged assets | ||||||||||||||||||
Zion Station decommissioning | -5 | -5 | 0 | 0 | 0 | |||||||||||||
Regulatory offset to decommissioning trust fund-related | ||||||||||||||||||
activities(b) | -338 | -338 | 0 | 0 | 0 | |||||||||||||
Total decommissioning-related activities | 209 | 209 | 0 | 0 | 0 | |||||||||||||
Investment income (expense) | 6 | -1 | 0 | -1 | 7 | (c) | ||||||||||||
Long-term lease income | 20 | 0 | 0 | 0 | 0 | |||||||||||||
Interest income related to uncertain income tax positions | 24 | 3 | 0 | 1 | 0 | |||||||||||||
AFUDC - Equity | 16 | 0 | 8 | 3 | 5 | |||||||||||||
Other | 36 | 18 | 10 | 1 | 1 | |||||||||||||
Other, net | $ | 311 | $ | 229 | $ | 18 | $ | 4 | $ | 13 | ||||||||
Three Months Ended September 30, 2012 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||
Other, Net | ||||||||||||||||||
Decommissioning-related activities: | ||||||||||||||||||
Net realized income on decommissioning trust funds (a) | ||||||||||||||||||
Regulatory agreement units | $ | 33 | $ | 33 | $ | 0 | $ | 0 | $ | 0 | ||||||||
Non-regulatory agreement units | 10 | 10 | 0 | 0 | 0 | |||||||||||||
Net unrealized gains on decommissioning trust funds | ||||||||||||||||||
Regulatory agreement units | 202 | 202 | 0 | 0 | 0 | |||||||||||||
Non-regulatory agreement units | 71 | 71 | 0 | 0 | 0 | |||||||||||||
Net unrealized gains on pledged assets | ||||||||||||||||||
Zion Station decommissioning | 22 | 22 | 0 | 0 | 0 | |||||||||||||
Regulatory offset to decommissioning trust fund-related | ||||||||||||||||||
activities(b) | -208 | -208 | 0 | 0 | 0 | |||||||||||||
Total decommissioning-related activities | 130 | 130 | 0 | 0 | 0 | |||||||||||||
Investment income | 5 | 1 | 0 | 0 | 3 | |||||||||||||
Long-term lease income | 7 | 0 | 0 | 0 | 0 | |||||||||||||
Interest income related to uncertain income tax positions | 0 | 1 | 1 | 0 | 0 | |||||||||||||
Credit facility termination fees | -43 | -43 | 0 | 0 | 0 | |||||||||||||
AFUDC - Equity | 4 | 0 | 1 | 1 | 2 | |||||||||||||
Other | -2 | -6 | 3 | 1 | 0 | |||||||||||||
Other, net | $ | 101 | $ | 83 | $ | 5 | $ | 2 | $ | 5 | ||||||||
Nine Months Ended September 30, 2012 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||
Other, Net | ||||||||||||||||||
Decommissioning-related activities: | ||||||||||||||||||
Net realized income on decommissioning trust funds (a) | ||||||||||||||||||
Regulatory agreement units | $ | 143 | $ | 143 | $ | 0 | $ | 0 | $ | 0 | ||||||||
Non-regulatory agreement units | 77 | 77 | 0 | 0 | 0 | |||||||||||||
Net unrealized gains on decommissioning trust funds | ||||||||||||||||||
Regulatory agreement units | 352 | 352 | 0 | 0 | 0 | |||||||||||||
Non-regulatory agreement units | 101 | 101 | 0 | 0 | 0 | |||||||||||||
Net unrealized gains on pledged assets | ||||||||||||||||||
Zion Station decommissioning | 60 | 60 | 0 | 0 | 0 | |||||||||||||
Regulatory offset to decommissioning trust fund-related | ||||||||||||||||||
activities(b) | -453 | -453 | 0 | 0 | 0 | |||||||||||||
Total decommissioning-related activities | 280 | 280 | 0 | 0 | 0 | |||||||||||||
Investment income | 15 | 2 | 1 | 2 | 9 | |||||||||||||
Long-term lease income | 22 | 0 | 0 | 0 | 0 | |||||||||||||
Interest income related to uncertain income tax positions | 14 | 1 | 1 | 0 | 0 | |||||||||||||
Credit facility termination fees | -85 | -85 | 0 | 0 | 0 | |||||||||||||
AFUDC - Equity | 11 | 0 | 2 | 3 | 8 | |||||||||||||
Other | -4 | -13 | 8 | 1 | 1 | |||||||||||||
Other, net | $ | 253 | $ | 185 | $ | 12 | $ | 6 | $ | 18 | ||||||||
__________ | ||||||||||||||||||
(a) Includes investment income and realized gains and losses on sales of investments of the trust funds. | ||||||||||||||||||
(b) Includes the elimination of NDT fund-related activity for the Regulatory Agreement Units, including the elimination of net income taxes related to all NDT fund activity for those units. See Note 13 – Asset Retirement Obligations of the Exelon 2012 Form 10-K for additional information regarding the accounting for nuclear decommissioning. | ||||||||||||||||||
(c) Relates to the cash return on BGE's rate stabilization deferral. See Note 5 - 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 nine months ended September 30, 2013 and 2012: | ||||||||||||||||||
Nine Months Ended September 30, 2013 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||
Depreciation, amortization, accretion and depletion | ||||||||||||||||||
Property, plant and equipment | $ | 1,420 | $ | 610 | $ | 413 | $ | 164 | $ | 194 | ||||||||
Regulatory assets | 153 | 0 | 88 | 7 | 58 | |||||||||||||
Amortization of intangible assets, net | 33 | 33 | 0 | 0 | 0 | |||||||||||||
Amortization of energy contract assets and liabilities (a) | 342 | 398 | 0 | 0 | 0 | |||||||||||||
Nuclear fuel (a) | 689 | 689 | 0 | 0 | 0 | |||||||||||||
ARO accretion (b) | 207 | 207 | 0 | 0 | 0 | |||||||||||||
Total depreciation, amortization, accretion and depletion | $ | 2,844 | $ | 1,937 | $ | 501 | $ | 171 | $ | 252 | ||||||||
Nine Months Ended September 30, 2012 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||
Depreciation, amortization, accretion and depletion | ||||||||||||||||||
Property, plant and equipment | $ | 1,263 | $ | 540 | $ | 396 | $ | 154 | $ | 184 | ||||||||
Regulatory assets | 89 | 0 | 62 | 7 | 34 | |||||||||||||
Amortization of intangible assets, net | 24 | 24 | 0 | 0 | 0 | |||||||||||||
Amortization of energy contract assets and liabilities (a) | 731 | 812 | 0 | 0 | 0 | |||||||||||||
Nuclear fuel (a) | 628 | 628 | 0 | 0 | 0 | |||||||||||||
ARO accretion (b) | 174 | 174 | 0 | 0 | 0 | |||||||||||||
Total depreciation, amortization, accretion and depletion | $ | 2,909 | $ | 2,178 | $ | 458 | $ | 161 | $ | 218 | ||||||||
__________ | ||||||||||||||||||
(a) Included in revenues or fuel expense, or operating revenues on the Registrants' Consolidated Statements of Operations and Comprehensive Income. | ||||||||||||||||||
(b) Included in operating and maintenance expense on the Registrants' Consolidated Statements of Operations. | ||||||||||||||||||
Nine Months Ended September 30, 2013 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||
Other non-cash operating activities: | ||||||||||||||||||
Pension and non-pension postretirement benefit costs | $ | 621 | $ | 259 | $ | 231 | $ | 32 | $ | 41 | ||||||||
Loss in equity method investments | -7 | -7 | 0 | 0 | 0 | |||||||||||||
Provision for uncollectible accounts | 83 | 16 | -6 | 48 | 25 | |||||||||||||
Stock-based compensation costs | 99 | 0 | 0 | 0 | 0 | |||||||||||||
Other decommissioning-related activity (a) | -110 | -110 | 0 | 0 | 0 | |||||||||||||
Energy-related options (b) | 87 | 87 | 0 | 0 | 0 | |||||||||||||
Amortization of regulatory asset related to debt costs | 9 | 0 | 7 | 2 | 0 | |||||||||||||
Amortization of rate stabilization deferral | 49 | 0 | 0 | 0 | 49 | |||||||||||||
Amortization of debt fair value adjustment | -28 | -28 | 0 | 0 | 0 | |||||||||||||
Discrete impacts from EIMA (c) | -206 | 0 | -206 | 0 | 0 | |||||||||||||
Amortization of debt costs | 13 | 7 | 3 | 2 | 1 | |||||||||||||
Merger integration costs (d) | -6 | 0 | 0 | 0 | -6 | |||||||||||||
Impairment of investments in direct financing leases (e) | 14 | 0 | 0 | 0 | 0 | |||||||||||||
Increase in inventory reserve | 7 | 7 | 0 | 0 | 0 | |||||||||||||
Impairment charges (f) | 149 | 149 | 0 | 0 | 0 | |||||||||||||
Other | -36 | -5 | -3 | 0 | -5 | |||||||||||||
Total other non-cash operating activities | $ | 738 | $ | 375 | $ | 26 | $ | 84 | $ | 105 | ||||||||
Changes in other assets and liabilities: | ||||||||||||||||||
Under/over-recovered energy and transmission costs | $ | -47 | $ | 0 | $ | -63 | $ | -10 | $ | 26 | ||||||||
Other regulatory assets and liabilities | -50 | 0 | -35 | 0 | -85 | |||||||||||||
Settlement of interest rate swaps (j) | 26 | 0 | 0 | 0 | 0 | |||||||||||||
Other current assets | -169 | -123 | -3 | -31 | -35 | |||||||||||||
Other noncurrent assets and liabilities | 205 | -40 | 261 | (g) | -6 | -25 | ||||||||||||
Total changes in other assets and liabilities | $ | -35 | $ | -163 | $ | 160 | $ | -47 | $ | -119 | ||||||||
Non-cash investing and financing activities: | ||||||||||||||||||
Consolidated VIE dividend to non-controlling interest | $ | 63 | $ | 63 | $ | 0 | $ | 0 | $ | 0 | ||||||||
Indemnification of like-kind exchange position (h) | 0 | 0 | 175 | 0 | 0 | |||||||||||||
Total non-cash investing and financing activities: | $ | 63 | $ | 63 | $ | 175 | $ | 0 | $ | 0 | ||||||||
Nine Months Ended September 30, 2012 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||
Other non-cash operating activities: | ||||||||||||||||||
Pension and non-pension postretirement benefit costs | $ | 606 | $ | 259 | $ | 212 | $ | 38 | $ | 44 | ||||||||
Provision for uncollectible accounts | 120 | 14 | 38 | 46 | 28 | |||||||||||||
Stock-based compensation costs | 75 | 0 | 0 | 0 | 0 | |||||||||||||
Other decommissioning-related activity (a) | -108 | -108 | 0 | 0 | 0 | |||||||||||||
Energy-related options (b) | 119 | 119 | 0 | 0 | 0 | |||||||||||||
Amortization of regulatory asset related to debt costs | 13 | 0 | 10 | 2 | 1 | |||||||||||||
Amortization of rate stabilization deferral | 39 | 0 | 0 | 0 | 49 | |||||||||||||
Amortization of debt fair value adjustment | -49 | -23 | 0 | 0 | 0 | |||||||||||||
Discrete impacts from EIMA (c) | 43 | 0 | 43 | 0 | 0 | |||||||||||||
Merger-related commitments (i) | 179 | 35 | 0 | 0 | 28 | |||||||||||||
Severance cost | 120 | 34 | 0 | 1 | 0 | |||||||||||||
Loss in equity method investments | 69 | 69 | 0 | 0 | 0 | |||||||||||||
Other | 9 | 23 | 7 | 9 | -2 | |||||||||||||
Total other non-cash operating activities | $ | 1,235 | $ | 422 | $ | 310 | $ | 96 | $ | 148 | ||||||||
Changes in other assets and liabilities: | ||||||||||||||||||
Under/over-recovered energy and transmission costs | $ | 20 | $ | 0 | $ | 21 | $ | -3 | $ | 21 | ||||||||
Other regulatory assets and liabilities | -454 | 0 | -65 | 7 | -80 | |||||||||||||
Other current assets | 52 | -85 | -8 | -56 | -25 | |||||||||||||
Other noncurrent assets and liabilities | -40 | -110 | -72 | -5 | 7 | |||||||||||||
Total changes in other assets and liabilities | $ | -422 | $ | -195 | $ | -124 | $ | -57 | $ | -77 | ||||||||
Non-cash investing and financing activities: | ||||||||||||||||||
Merger with Constellation, common stock issued | $ | 7,365 | $ | 5,258 | $ | 0 | $ | 0 | $ | 0 | ||||||||
DOE Smart Grid Investment Grant (Exelon, PECO and BGE). For the nine months ended September 30, 2013, Exelon, PECO and BGE have included in the Capital expenditures line item under investing activities of the cash flow statement capital expenditures of $68 million, $22 million and $46 million, respectively, and reimbursements of $64 million, $30 million and $34 million, respectively, related to PECO's and BGE's DOE SGIG programs. For the nine months ended September 30, 2012, Exelon, PECO and BGE have included in the Capital expenditures line item under investing activities of the cash flow statement capital expenditures of $75 million, $45 million and $30 million, respectively, and reimbursements of $85 million, $55 million and $30 million, respectively, related to PECO's and BGE's DOE SGIG programs. See Note 5 - Regulatory Matters for additional information regarding the DOE SGIG. | ||||||||||||||||||
_________ | ||||||||||||||||||
(a) Includes the elimination of NDT fund-related 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 13 of the Exelon 2012 Form 10-K 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 5 - Regulatory Matters for more information. | ||||||||||||||||||
(d) Relates to integration costs to achieve distribution synergies related to the merger transaction. See Note 5 - Regulatory Matters for more information. | ||||||||||||||||||
(e) Relates to an other than temporary decline in the estimated residual value of one of Exelon's direct financing leases. See Note 7 – Impairment of Long-Lived Assets for more information. | ||||||||||||||||||
(f) Relates to the cancellation of uprate projects and write down of certain wind projects at Generation. See Note 7 – Impairment of Long-Lived Assets for additional information. | ||||||||||||||||||
(g) Relates primarily to interest payable related to like-kind exchange tax position. See Note 12 – Income Taxes for discussion of the like-kind exchange tax position. | ||||||||||||||||||
(h) See Note 12 – Income Taxes for discussion of the like-kind exchange tax position. | ||||||||||||||||||
(i) See Note 4 - Mergers and Acquisitions for more information on merger-related commitments. | ||||||||||||||||||
(i) Relates to settlement of forward starting interest rate swaps that Exelon entered into in anticipation of the Continental Wind, LLC non-recourse project financing that was completed on September 30, 2013. See Note 10 – Derivative Financial Instruments for more information on interest rate swaps. | ||||||||||||||||||
Supplemental Balance Sheet Information | ||||||||||||||||||
The following tables provide additional information about assets and liabilities of the Registrants as of September 30, 2013 and December 31, 2012. | ||||||||||||||||||
30-Sep-13 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||
Property, plant and equipment: | ||||||||||||||||||
Accumulated depreciation and amortization | $ | 13,366 | (a) | $ | 6,848 | (a) | $ | 3,107 | $ | 2,914 | $ | 2,658 | ||||||
Accounts receivable: | ||||||||||||||||||
Allowance for uncollectible accounts | 302 | 72 | 73 | 119 | 38 | |||||||||||||
31-Dec-12 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||
Property, plant and equipment: | ||||||||||||||||||
Accumulated depreciation and amortization | $ | 12,184 | (b) | $ | 6,014 | (b) | $ | 2,998 | $ | 2,797 | $ | 2,595 | ||||||
Accounts receivable: | ||||||||||||||||||
Allowance for uncollectible accounts | 293 | 84 | 70 | 99 | 40 | |||||||||||||
___________ | ||||||||||||||||||
(a) Includes accumulated amortization of nuclear fuel in the reactor core of $2,365 million. | ||||||||||||||||||
(b) Includes accumulated amortization of nuclear fuel in the reactor core of $2,078 million. | ||||||||||||||||||
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 $22 million as of September 30, 2013 and $18 million as of December 31, 2012. 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 Account Policies of the Exelon 2012 Form 10-K. The allowance for uncollectible accounts balance associated with these receivables at September 30, 2013 of $22 million consists of $1 million, $4 million and $17 million for low risk, medium risk and high risk segments, respectively. The allowance for uncollectible accounts balance at December 31, 2012 of $15 million consists of $1 million, $3 million and $11 million for low risk, medium risk and high risk segments, respectively. The balance of the payment agreement is billed to the customer in equal monthly installments over the term of the agreement. Installment receivables outstanding as of September 30, 2013 and December 31, 2012 include balances not yet presented on the customer bill, accounts currently billed and an immaterial amount of past due receivables. When a customer defaults on its payment agreement, the terms of which are defined by plan type, the entire balance of the agreement becomes due and the balance is reclassified to current customer accounts receivable and reserved for in accordance with the methodology discussed in Note 1 – Significant Accounting Policies of the Exelon 2012 Form 10-K. | ||||||||||||||||||
Segment_Information_Exelon_Gen
Segment Information (Exelon, Generation, ComEd, PECO and BGE) | 9 Months Ended | ||||||||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||||||||
Segment Information [Line Items] | ' | ||||||||||||||||||||||
Segment Information (Exelon, Generation, ComEd, PECO and BGE) | ' | ||||||||||||||||||||||
20. Segment Information (Exelon, Generation, ComEd, PECO and BGE) | |||||||||||||||||||||||
Exelon has nine reportable segments, ComEd, PECO, BGE and Generation's six power marketing reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and all other regions not considered individually significant referred to collectively as “Other Regions”; including the South, West and Canada. Generation's expanded number of reportable segments is the result of the acquisition of Constellation on March 12, 2012. ComEd, PECO and BGE each represent a single reportable segment; as such, no separate segment information is provided for these Registrants. Exelon evaluates the performance of ComEd, PECO and BGE based on net income. | |||||||||||||||||||||||
The 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 entire United States footprint of MISO, 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 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. | |||||||||||||||||||||||
Exelon and Generation evaluate the performance of Generation's power marketing activities based on revenue net of purchased power and fuel expense. Generation believes that revenue net of purchased power and fuel expense is a useful measurement of operational performance. Revenue net of purchased power and fuel expense is not a presentation defined under GAAP and may not be comparable to other companies' presentations or deemed more useful than the GAAP information provided elsewhere in this report. Generation's operating revenues include all sales to third parties and affiliated sales to ComEd, PECO and BGE. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for Generation's own generation and fuel costs associated with tolling agreements. Generation's other business activities, including retail and wholesale gas, upstream natural gas, proprietary trading, energy efficiency and demand response, heating, cooling, and cogeneration facilities, and home improvements, sales of electric and gas appliances, servicing of heating, air conditioning, plumbing, electrical, and indoor quality systems, and investments in energy-related proprietary technology are not allocated to regions. Further, Generation's compensation under the reliability-must-run rate schedule, results of operations from the Brandon Shores, Wagner, and C.P. Crane Maryland generating stations, and other miscellaneous revenues, mark-to-market impact of economic hedging activities, and amortization of certain intangible assets relating to commodity contracts recorded at fair value as a result of the merger are also not allocated to a region. | |||||||||||||||||||||||
An analysis and reconciliation of the Registrants' reportable segment information to the respective information in the consolidated financial statements for the three and nine months ended September 30, 2013 and 2012 is as follows: | |||||||||||||||||||||||
Three Months Ended September 30, 2013 and 2012 | |||||||||||||||||||||||
Intersegment Eliminations | |||||||||||||||||||||||
Generation (a) | ComEd | PECO | BGE | Other(b) | Exelon | ||||||||||||||||||
Total revenues(c): | |||||||||||||||||||||||
2013 | $ | 4,255 | $ | 1,156 | $ | 728 | $ | 737 | $ | 294 | $ | -668 | $ | 6,502 | |||||||||
2012 | 4,031 | 1,484 | 806 | 720 | 336 | -798 | 6,579 | ||||||||||||||||
Intersegment revenues(d): | |||||||||||||||||||||||
2013 | $ | 373 | $ | 1 | $ | 1 | $ | 2 | $ | 294 | $ | -669 | $ | 2 | |||||||||
2012 | 459 | 0 | 1 | 4 | 337 | -798 | 3 | ||||||||||||||||
Net income (loss): | |||||||||||||||||||||||
2013 | $ | 485 | $ | 126 | $ | 92 | $ | 53 | $ | -20 | $ | 0 | $ | 736 | |||||||||
2012 | 87 | 90 | 123 | 0 | -3 | 0 | 297 | ||||||||||||||||
Total assets: | |||||||||||||||||||||||
30-Sep-13 | $ | 40,498 | $ | 23,686 | $ | 9,745 | $ | 7,657 | $ | 9,563 | $ | -11,488 | $ | 79,661 | |||||||||
31-Dec-12 | 40,681 | 22,905 | 9,353 | 7,506 | 10,432 | -12,316 | 78,561 | ||||||||||||||||
__________ | |||||||||||||||||||||||
(a) Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions. Intersegment revenues for Generation for the three months ended September 30, 2013 include revenue from sales to PECO of $ 82 million and sales to BGE of $ 144 million in the Mid-Atlantic region, and sales to ComEd of $ 143 million in the Midwest. For the three months ended September 30, 2012 intersegment revenues for Generation include revenue from sales to PECO of $171 million and sales to BGE of $120 million in the Mid-Atlantic region, and sales to ComEd of $180 million in the Midwest region, net of $15 million related to the unrealized mark-to-market losses related to the ComEd swap, which eliminate upon consolidation. | |||||||||||||||||||||||
(b) Other primarily includes Exelon's corporate operations, shared service entities and other financing and investment activities. | |||||||||||||||||||||||
(c) For the three months ended September 30, 2013 and 2012, utility taxes of $21 million and $28 million, respectively, are included in revenues and expenses for Generation. For the three months ended September 30, 2013 and 2012, utility taxes of $65 million and $67 million, respectively, are included in revenues and expenses for ComEd. For the three months ended September 30, 2013 and 2012, utility taxes of $33 million and $40 million, respectively, are included in revenues and expenses for PECO. For the three months ended September 30, 2013 and 2012, utility taxes of $20 million and $20 million, respectively, are included in revenues and expenses for BGE. | |||||||||||||||||||||||
(d) Intersegment revenues exclude sales to unconsolidated affiliate entities. 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 Statements of Operations. | |||||||||||||||||||||||
Generation total revenues (three months ended): | |||||||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||||
Revenues from external customers (a) | Intersegment revenues | Total Revenues | Revenues from external customers (a) | Intersegment revenues | Total Revenues | ||||||||||||||||||
Mid-Atlantic | $ | 1,381 | $ | 10 | $ | 1,391 | $ | 1,428 | $ | -11 | $ | 1,417 | |||||||||||
Midwest | 1,018 | -5 | 1,013 | 1,193 | 7 | 1,200 | |||||||||||||||||
New England | 341 | -1 | 340 | 390 | 1 | 391 | |||||||||||||||||
New York | 198 | -14 | 184 | 183 | 2 | 185 | |||||||||||||||||
ERCOT | 430 | -3 | 427 | 532 | 1 | 533 | |||||||||||||||||
Other Regions (b) | 278 | -7 | 271 | 317 | 12 | 329 | |||||||||||||||||
Total Revenues for Reportable Segments | 3,646 | -20 | 3,626 | 4,043 | 12 | 4,055 | |||||||||||||||||
Other (c) | 609 | 20 | 629 | -12 | -12 | -24 | |||||||||||||||||
Total Generation Consolidated Operating Revenues | $ | 4,255 | $ | 0 | $ | 4,255 | $ | 4,031 | $ | - | $ | 4,031 | |||||||||||
(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 $125 million and $404 million, for the three months ended September 30, 2013 and 2012, respectively, and elimination of intersegment revenues. | |||||||||||||||||||||||
Generation total revenues net of purchased power and fuel expense (three months ended): | |||||||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||||
RNF from external customers (a) | Intersegment RNF | Total RNF | RNF from external customers (a) | Intersegment RNF | Total RNF | ||||||||||||||||||
Mid-Atlantic | $ | 857 | $ | 7 | $ | 864 | $ | 919 | $ | -11 | $ | 908 | |||||||||||
Midwest | 606 | -5 | 601 | 723 | 7 | 730 | |||||||||||||||||
New England | 52 | 10 | 62 | 80 | 1 | 81 | |||||||||||||||||
New York | 29 | -38 | -9 | 11 | 2 | 13 | |||||||||||||||||
ERCOT | 222 | -78 | 144 | 158 | - | 158 | |||||||||||||||||
Other Regions (b) | 116 | -75 | 41 | 30 | 12 | 42 | |||||||||||||||||
Total Revenues net of purchased power and fuel expense for Reportable Segments | 1,882 | -179 | 1,703 | 1,921 | 11 | 1,932 | |||||||||||||||||
Other (c) | 194 | 179 | 373 | -12 | -11 | -23 | |||||||||||||||||
Total Generation Revenues net of purchased power and fuel expense | $ | 2,076 | $ | 0 | $ | 2,076 | $ | 1,909 | $ | - | $ | 1,909 | |||||||||||
(a) Includes purchases and sales from third parties and affiliated sales to ComEd, PECO and BGE. | |||||||||||||||||||||||
(b) Other regions includes 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 $44 million and $257 million for the three months ended September 30, 2013 and 2012, respectively. | |||||||||||||||||||||||
Nine Months Ended September 30, 2013 and 2012 | |||||||||||||||||||||||
Intersegment Eliminations | |||||||||||||||||||||||
Generation (a) | ComEd | PECO | BGE(b) | Other(c) | Exelon | ||||||||||||||||||
Total revenues(d): | |||||||||||||||||||||||
2013 | $ | 11,858 | $ | 3,395 | $ | 2,295 | $ | 2,271 | $ | 909 | $ | -2,003 | $ | 18,725 | |||||||||
2012 | 10,539 | 4,154 | 2,396 | 1,388 | 1,049 | -2,291 | 17,235 | ||||||||||||||||
Intersegment revenues(e): | |||||||||||||||||||||||
2013 | $ | 1,083 | $ | 2 | $ | 1 | $ | 10 | $ | 909 | $ | -2,003 | $ | 2 | |||||||||
2012 | 1,233 | 2 | 3 | 7 | 1,050 | -2,291 | 4 | ||||||||||||||||
Net income (loss): | |||||||||||||||||||||||
2013 | $ | 795 | $ | 140 | $ | 292 | $ | 160 | $ | -152 | $ | 0 | $ | 1,235 | |||||||||
2012 | 419 | 219 | 300 | -50 | -101 | 0 | 787 | ||||||||||||||||
__________ | |||||||||||||||||||||||
(a) Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions. Intersegment revenues for Generation for the nine months ended September 30, 2013 include revenue from sales to PECO of $ 321 million and sales to BGE of $ 356 million in the Mid-Atlantic region, and sales to ComEd of $ 409 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 nine months ended September 30, 2012 intersegment revenues for Generation include revenue from sales to PECO of $407 million in the Mid-Atlantic region and sales to BGE of $223 million in the Mid-Atlantic region, and sales to ComEd of $631 million in the Midwest region, net of $30 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 September 30, 2012. | |||||||||||||||||||||||
(c) Other primarily includes Exelon's corporate operations, shared service entities and other financing and investment activities. | |||||||||||||||||||||||
(d) For the nine months ended September 30, 2013 and 2012, utility taxes of $60 million and $60 million, respectively, are included in revenues and expenses for Generation. For the nine months ended September 30, 2013 and 2012, utility taxes of $182 million and $182 million, respectively, are included in revenues and expenses for ComEd. For the nine months ended September 30, 2013 and 2012, utility taxes of $97 million and $108 million, respectively, are included in revenues and expenses for PECO. For the nine months ended September 30, 2013 and period of March 12, 2012 through September 30, 2012, utility taxes of $62 million and $42 million, respectively, are included in revenues and expenses for BGE. | |||||||||||||||||||||||
(e) Intersegment revenues exclude sales to unconsolidated affiliate entities. 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 Statements of Operations. | |||||||||||||||||||||||
Generation total revenues (nine months ended): | |||||||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||||
Revenues from external customers (a) | Intersegment revenues | Total Revenues | Revenues from external customers (a) | Intersegment revenues | Total Revenues | ||||||||||||||||||
Mid-Atlantic | $ | 3,932 | $ | 11 | $ | 3,943 | $ | 3,832 | $ | -43 | $ | 3,789 | |||||||||||
Midwest | 3,274 | -3 | 3,271 | 3,600 | 19 | 3,619 | |||||||||||||||||
New England | 942 | -9 | 933 | 776 | 36 | 812 | |||||||||||||||||
New York | 547 | -20 | 527 | 394 | -22 | 372 | |||||||||||||||||
ERCOT | 1,042 | -8 | 1,034 | 1,073 | 1 | 1,074 | |||||||||||||||||
Other Regions (b) | 708 | 29 | 737 | 611 | 40 | 651 | |||||||||||||||||
Total Revenues for Reportable Segments | 10,445 | 0 | 10,445 | 10,286 | 31 | 10,317 | |||||||||||||||||
Other (c) | 1,413 | 0 | 1,413 | 253 | -31 | 222 | |||||||||||||||||
Total Generation Consolidated Operating Revenues | $ | 11,858 | $ | 0 | $ | 11,858 | $ | 10,539 | $ | 0 | $ | 10,539 | |||||||||||
(a) Includes all wholesale and retail electric 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 at the merger date of $603 million and $1,089 million, for the nine months ended September 30, 2013 and 2012, respectively, and elimination of intersegment revenues. | |||||||||||||||||||||||
Generation total revenues net of purchased power and fuel expense (nine months ended): | |||||||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||||
RNF from external customers (a) | Intersegment RNF | Total RNF | RNF from external customers (a) | Intersegment RNF | Total RNF | ||||||||||||||||||
Mid-Atlantic | $ | 2,477 | $ | -2 | $ | 2,475 | $ | 2,605 | $ | -44 | $ | 2,561 | |||||||||||
Midwest | 2,002 | -1 | 2,001 | 2,291 | 19 | 2,310 | |||||||||||||||||
New England | 156 | -14 | 142 | 144 | 36 | 180 | |||||||||||||||||
New York | 14 | -31 | -17 | 82 | -22 | 60 | |||||||||||||||||
ERCOT | 477 | -120 | 357 | 311 | 1 | 312 | |||||||||||||||||
Other Regions (b) | 238 | -91 | 147 | 49 | 41 | 90 | |||||||||||||||||
Total Revenues net of purchased power and fuel expense for Reportable Segments | 5,364 | -259 | 5,105 | 5,482 | 31 | 5,513 | |||||||||||||||||
Other (c) | 200 | 259 | 459 | 39 | -31 | 8 | |||||||||||||||||
Total Generation Revenues net of purchased power and fuel expense | $ | 5,564 | $ | 0 | $ | 5,564 | $ | 5,521 | $ | 0 | $ | 5,521 | |||||||||||
(a) Includes purchases and sales from third parties and affiliated sales to ComEd, PECO and BGE. | |||||||||||||||||||||||
(b) Other regions includes 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 at the merger date of $386 million and $793 million, for the nine months ended September 30, 2013 and 2012, respectively. |
Fair_Value_of_Financial_Assets1
Fair Value of Financial Assets and Liabilities (Policies) | 9 Months Ended |
Sep. 30, 2013 | |
Fair Value Of Financial Liabilities Recorded At The Carrying Amount [Abstract] | ' |
Cash Equivalents Valuation Techniques Used to Determine Fair Value | ' |
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 Valuation Techniques Used to Determine Fair Value | ' |
Nuclear Decommissioning Trust Fund Investments and Pledged Assets for Zion Station Decommissioning (Exelon and Generation). The trust fund investments have been established to fund Generation's nuclear decommissioning obligations as required by the NRC. The NDT funds hold debt and equity securities directly and indirectly through commingled funds. Generation's investment policies place limitations on the types and investment grade ratings of the securities that may be held by the trusts. These policies limit the trust funds' exposures to investments in highly illiquid markets and other alternative investments. Investments with maturities of three months or less when purchased, including certain short-term fixed income securities are considered cash equivalents and included in the recurring fair value measurements hierarchy as Level 1. | |
With respect to individually held equity securities and exchange traded funds, 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 and exchange traded funds, held directly by the trust funds are based on quoted prices in active markets and are categorized in Level 1. Equity securities held individually and exchange traded funds 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. | |
Equity and fixed income commingled funds and fixed income mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives. The fair values of fixed income commingled and mutual funds held within the trust funds, which generally hold short-term fixed income securities and are not subject to restrictions regarding the purchase or sale of shares, are derived from observable prices. The objectives of the remaining equity commingled funds in which Exelon and Generation invest primarily seek to track the performance of certain equity indices by purchasing equity securities to replicate the capitalization and characteristics of the indices. In general, equity commingled funds are redeemable daily. Equity and fixed income 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. See Note 13 — Nuclear Decommissioning for further discussion on the NDT fund investments. | |
Middle market lending funds are investments in loans or managed funds which invest in private companies. Generation elected the fair value option for its investments held by certain limited partnerships that invest in middle market lending managed funds. The fair value of these loans is determined using a combination of valuation models including cost models, market models, and income models. Investments in middle market lending are categorized as Level 3 because the fair value of these securities is based largely on inputs that are unobservable and utilize complex valuation models. Investments in middle market lending typically cannot be redeemed until maturity of the term loan. | |
Rabbi Trust Investments Valuation Techniques Used to Determine Fair Value | ' |
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. The investments are in fixed-income commingled funds and mutual funds, including short-term investment 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. Fixed-income commingled funds and mutual funds, such as money market funds, are publicly quoted and have been categorized as Level 1 given the clear observability of the prices. | |
Mark-to-Market Valuation Techniques Used to Determine Fair Value | ' |
Mark-to-Market Derivatives (Exelon, Generation, and ComEd). Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy. Certain derivatives' pricing is verified using indicative price quotations available through brokers or over-the-counter, on-line exchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask, mid-point prices and are obtained from sources that the Registrants believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. This includes consideration of actual transaction volumes, market delivery points, bid-ask spreads and contract duration. The remainder of derivative contracts are valued using the Black model, an industry standard option valuation model. The Black model takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the future prices of energy, interest rates, volatility, credit worthiness and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps and options, model inputs are generally observable. Such instruments are categorized in Level 2. The Registrants' derivatives are predominately at liquid trading points. For derivatives that trade in less liquid markets with limited pricing information model inputs generally would include both observable and unobservable inputs. These valuations may include an estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. Such instruments are categorized in Level 3. | |
Transfers in and out of levels are recognized as of the end of the reporting period the transfer occurred. Given derivatives categorized within Level 1 are valued using exchange-based quoted prices within observable periods, transfers between Level 2 and Level 1 were not material. Transfers into Level 2 from Level 3 generally occur when the contract tenure becomes more observable. Transfers into Level 3 from Level 2 generally occur due to changes in market liquidity or assumptions for certain commodity contracts. | |
Exelon may utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to achieve its targeted level of variable-rate debt as a percent of total debt. In addition, the Registrants may utilize interest rate derivatives to lock in interest rate levels in anticipation of future financings. These interest rate derivatives are typically designated as cash flow hedges. Exelon determines the current fair value by calculating the net present value of expected payments and receipts under the swap agreement, based on and discounted by the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk and other market parameters. As these inputs are based on observable data and valuations of similar instruments, the interest rate swaps are categorized in Level 2 in the fair value hierarchy. See Note 10 — Derivative Financial Instruments for further discussion on mark-to-market derivatives. | |
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. | |
Deferred Compensation Obligations Valuation Techniques Used to Determine Fair Value | ' |
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 in Level 2 in the fair value hierarchy. |
Variable_Interest_Entities_Tab
Variable Interest Entities (Tables) | 9 Months Ended | ||||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||||
Variable Interest Entity [Line Items] | ' | ||||||||||||||||||
Schedule of Variable Interest Entities [Table Text Block] | ' | ||||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||||
Exelon (a)(b) | Generation (b) | BGE | Exelon (a)(b)(c) | Generation (b)(c) | BGE | ||||||||||||||
Current assets | $ | 391 | $ | 330 | $ | 50 | $ | 550 | $ | 519 | $ | 30 | |||||||
Noncurrent assets | 1,900 | 1,877 | 3 | 1,802 | 1,762 | - | |||||||||||||
Total assets | $ | 2,291 | $ | 2,207 | $ | 53 | $ | 2,352 | $ | 2,281 | $ | 30 | |||||||
Current liabilities | $ | 453 | $ | 366 | $ | 77 | $ | 685 | $ | 613 | $ | 71 | |||||||
Noncurrent liabilities | 859 | 608 | 230 | 837 | 532 | 265 | |||||||||||||
Total liabilities | $ | 1,312 | $ | 974 | $ | 307 | $ | 1,522 | $ | 1,145 | $ | 336 | |||||||
Schedule Of Unconsolidated Variable Interest Entities [Text Block] | ' | ||||||||||||||||||
Equity | |||||||||||||||||||
Commercial | Method | ||||||||||||||||||
Agreement | Investment | ||||||||||||||||||
30-Sep-13 | VIEs | VIEs | Total | ||||||||||||||||
Total assets (a) | $ | 115 | $ | 366 | $ | 481 | |||||||||||||
Total liabilities (a) | 3 | 126 | 129 | ||||||||||||||||
Registrants' ownership interest (a) | 0 | 97 | 97 | ||||||||||||||||
Other ownership interests (a) | 112 | 143 | 255 | ||||||||||||||||
Registrants' maximum exposure to loss: | |||||||||||||||||||
Carrying amount of equity method investments | 0 | 78 | 78 | ||||||||||||||||
Contract intangible asset | 9 | 0 | 9 | ||||||||||||||||
Debt and payment guarantees | 0 | 5 | 5 | ||||||||||||||||
Net assets pledged for Zion Station decommissioning (b) | 43 | 0 | 43 | ||||||||||||||||
Equity | |||||||||||||||||||
Commercial | Method | ||||||||||||||||||
Agreement | Investment | ||||||||||||||||||
31-Dec-12 | VIEs | VIEs | Total | ||||||||||||||||
Total assets (a) | $ | 386 | $ | 354 | $ | 740 | |||||||||||||
Total liabilities (a) | 219 | 114 | 333 | ||||||||||||||||
Registrants' ownership interest (a) | 0 | 97 | 97 | ||||||||||||||||
Other ownership interests (a) | 167 | 143 | 310 | ||||||||||||||||
Registrants' maximum exposure to loss: | |||||||||||||||||||
Letters of credit | 5 | 0 | 5 | ||||||||||||||||
Carrying amount of equity method investments | 0 | 77 | 77 | ||||||||||||||||
Contract intangible asset | 8 | 0 | 8 | ||||||||||||||||
Debt and payment guarantees | 0 | 5 | 5 | ||||||||||||||||
Net assets pledged for Zion Station decommissioning (b) | 50 | 0 | 50 | ||||||||||||||||
These items represent amounts on the unconsolidated VIE balance sheets, not on Exelon's or Generation's Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs. | |||||||||||||||||||
These items represent amounts on Exelon's and Generation's Consolidated Balance Sheets related to the asset sale agreement with ZionSolutions, LLC. The net assets pledged for Zion Station decommissioning includes gross pledged assets of $486 million and $614 million as of September 30, 2013 and December 31, 2012, respectively; offset by payables to ZionSolutions LLC of $443 million and $564 million as of September 30, 2013 and December 31, 2012, respectively. These items are included to provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE. | |||||||||||||||||||
Merger_and_Acquisitions_Tables
Merger and Acquisitions (Tables) | 9 Months Ended | ||||||||||||||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | ' | ||||||||||||||||||||||||||||
Schedule of Finite-Lived Intangible Assets Acquired as Part of Business Combination [Table Text Block] | ' | ||||||||||||||||||||||||||||
Estimated amortization expense | |||||||||||||||||||||||||||||
Description | Weighted Average Amortization (Years) (b) | Gross | Accumulated Amortization | Net | Remainder of 2013 | 2014 | 2015 | 2016 | 2017 | 2018 and Beyond | |||||||||||||||||||
Unamortized energy contracts, net (a) | 1.5 | $ | 1,499 | $ | -1,299 | $ | 200 | $ | 79 | $ | 75 | $ | 18 | $ | -31 | $ | -21 | $ | 80 | ||||||||||
Trade name | 10 | 243 | -40 | 203 | 6 | 24 | 24 | 24 | 24 | 101 | |||||||||||||||||||
Retail relationships | 12.4 | 214 | -31 | 183 | 5 | 19 | 18 | 18 | 18 | 105 | |||||||||||||||||||
Total, net | $ | 1,956 | $ | -1,370 | $ | 586 | $ | 90 | $ | 118 | $ | 60 | $ | 11 | $ | 21 | $ | 286 | |||||||||||
Includes the fair value of BGE's power and gas supply contracts of $32 million for which an offsetting regulatory asset was also recorded. | |||||||||||||||||||||||||||||
Weighted average amortization period was calculated as of the date of acquisition. | |||||||||||||||||||||||||||||
Schedule of Restructuring and Related Costs [Text Block] | ' | ||||||||||||||||||||||||||||
Three Months Ended September 30, 2012 | |||||||||||||||||||||||||||||
Severance Benefits (a) | Exelon | Generation | ComEd (b) | PECO | BGE (c) | ||||||||||||||||||||||||
Severance charges | $ | 8 | $ | 4 | $ | 1 | $ | 1 | $ | 1 | |||||||||||||||||||
Stock compensation | 3 | 2 | 1 | 0 | 0 | ||||||||||||||||||||||||
Total severance benefits | $ | 11 | $ | 6 | $ | 2 | $ | 1 | $ | 1 | |||||||||||||||||||
Nine Months Ended September 30, 2012 | |||||||||||||||||||||||||||||
Severance Benefits (a) | Exelon | Generation | ComEd (b) | PECO | BGE (c) | ||||||||||||||||||||||||
Severance charges | $ | 117 | $ | 68 | $ | 16 | $ | 8 | $ | 18 | |||||||||||||||||||
Stock compensation | 6 | 4 | 1 | 0 | 0 | ||||||||||||||||||||||||
Other charges (d) | 7 | 4 | 1 | 0 | 1 | ||||||||||||||||||||||||
Total severance benefits | $ | 130 | $ | 76 | $ | 18 | $ | 8 | $ | 19 | |||||||||||||||||||
_________________ | |||||||||||||||||||||||||||||
The amounts above include $0 million and $40 million at Generation, $2 million and $16 million at ComEd, $1 million and $8 million at PECO, and $1 million and $7 million at BGE, for amounts billed by BSC through intercompany allocations for the three and nine months ended September 30, 2012, respectively. | |||||||||||||||||||||||||||||
ComEd established regulatory assets of $2 million and $18 million for severance benefits costs for the three and nine months ended September 30, 2012, respectively. The majority of these costs are expected to be recovered over a five-year period. | |||||||||||||||||||||||||||||
BGE established regulatory assets of $1 million and $19 million for severance benefits costs for the three and nine months ended September 30, 2012, respectively. The majority of these costs are being recovered over a five-year period beginning in March 2013. | |||||||||||||||||||||||||||||
(d) Primarily includes life insurance, employer payroll taxes, educational assistance and outplacement services. | |||||||||||||||||||||||||||||
Schedule of Restructuring Reserve by Type of Cost [Table Text Block] | ' | ||||||||||||||||||||||||||||
Nine Months Ended September 30, 2013 | |||||||||||||||||||||||||||||
Severance liability | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||||||||||
Balance at December 31, 2012 | $ | 111 | $ | 33 | $ | 1 | $ | 0 | $ | 11 | |||||||||||||||||||
Severance charges (a) | 5 | 1 | 0 | 0 | 0 | ||||||||||||||||||||||||
Stock compensation | 1 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||||
Payments | -52 | -20 | 0 | 0 | -4 | ||||||||||||||||||||||||
Balance at September 30, 2013 | $ | 65 | $ | 14 | $ | 1 | $ | 0 | $ | 7 | |||||||||||||||||||
Includes salary continuance and health and welfare severance benefits. Amounts represent ongoing severance plan benefits. | |||||||||||||||||||||||||||||
Business Acquisition, Pro Forma Information [Table Text Block] | ' | ||||||||||||||||||||||||||||
Three Months Ended September 30, 2012 | |||||||||||||||||||||||||||||
Generation | Exelon | ||||||||||||||||||||||||||||
Total Revenues | $ | 4,293 | $ | 6,841 | |||||||||||||||||||||||||
Net income attributable to Exelon | 282 | 492 | |||||||||||||||||||||||||||
Basic Earnings Per Share | n.a. | $ | 0.58 | ||||||||||||||||||||||||||
Diluted Earnings Per Share | n.a. | 0.57 | |||||||||||||||||||||||||||
Nine Months Ended September 30, 2012 | |||||||||||||||||||||||||||||
Generation | Exelon | ||||||||||||||||||||||||||||
Total Revenues | $ | 12,753 | $ | 20,084 | |||||||||||||||||||||||||
Net income attributable to Exelon | 805 | 1,439 | |||||||||||||||||||||||||||
Basic Earnings Per Share | n.a. | $ | 1.79 | ||||||||||||||||||||||||||
Diluted Earnings Per Share | n.a. | 1.79 | |||||||||||||||||||||||||||
Schedule Of Business Acquisitions By Acquisition [Text Block] | ' | ||||||||||||||||||||||||||||
Purchase Price Allocation, excluding amortization | Exelon | Generation | |||||||||||||||||||||||||||
Current assets | $ | 4,936 | $ | 3,638 | |||||||||||||||||||||||||
Property, plant and equipment | 9,342 | 4,054 | |||||||||||||||||||||||||||
Unamortized energy contracts | 3,218 | 3,218 | |||||||||||||||||||||||||||
Other intangibles, trade name and retail relationships | 457 | 457 | |||||||||||||||||||||||||||
Investment in affiliates | 1,942 | 1,942 | |||||||||||||||||||||||||||
Pension and OPEB regulatory asset | 740 | 0 | |||||||||||||||||||||||||||
Other assets | 2,265 | 1,266 | |||||||||||||||||||||||||||
Total assets | 22,900 | 14,575 | |||||||||||||||||||||||||||
Current liabilities | 3,408 | 2,804 | |||||||||||||||||||||||||||
Unamortized energy contracts | 1,722 | 1,512 | |||||||||||||||||||||||||||
Long-term debt, including current maturities | 5,632 | 2,972 | |||||||||||||||||||||||||||
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 |
Regulatory_Matters_Tables
Regulatory Matters (Tables) | 9 Months Ended | ||||||||||||||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||||||||||||||
Regulatory Matters [Line Items] | ' | ||||||||||||||||||||||||||||
Regulatory assets and liabilities | ' | ||||||||||||||||||||||||||||
30-Sep-13 | Exelon | ComEd | PECO | BGE | |||||||||||||||||||||||||
Regulatory assets | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | |||||||||||||||||||||
Pension and other postretirement | |||||||||||||||||||||||||||||
benefits | $ | 308 | $ | 3,542 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | |||||||||||||
Deferred income taxes | 12 | 1,424 | 3 | 65 | 0 | 1,296 | 9 | 63 | |||||||||||||||||||||
AMI programs | 4 | 129 | 4 | 29 | 0 | 48 | 0 | 52 | |||||||||||||||||||||
AMI meter events | 0 | 5 | 0 | 0 | 0 | 5 | 0 | 0 | |||||||||||||||||||||
Under-recovered distribution service | |||||||||||||||||||||||||||||
costs | 129 | 275 | 129 | 275 | 0 | 0 | 0 | 0 | |||||||||||||||||||||
Debt costs | 12 | 60 | 9 | 56 | 3 | 4 | 1 | 9 | |||||||||||||||||||||
Fair value of BGE long-term debt (a) | 0 | 225 | 0 | 0 | 0 | 0 | 0 | 0 | |||||||||||||||||||||
Fair value of BGE supply contract (b) | 29 | 3 | 0 | 0 | 0 | 0 | 0 | 0 | |||||||||||||||||||||
Severance | 23 | 13 | 19 | 0 | 0 | 0 | 4 | 13 | |||||||||||||||||||||
Asset retirement obligations | 0 | 93 | 0 | 68 | 0 | 25 | 0 | 0 | |||||||||||||||||||||
MGP remediation costs | 47 | 210 | 40 | 175 | 6 | 34 | 1 | 1 | |||||||||||||||||||||
RTO start-up costs | 2 | 1 | 2 | 1 | 0 | 0 | 0 | 0 | |||||||||||||||||||||
Under-recovered uncollectible | |||||||||||||||||||||||||||||
accounts | 0 | 31 | 0 | 31 | 0 | 0 | 0 | 0 | |||||||||||||||||||||
Renewable energy and associated | |||||||||||||||||||||||||||||
RECs | 16 | 106 | 16 | 106 | 0 | 0 | 0 | 0 | |||||||||||||||||||||
Energy and transmission programs | 79 | 0 | 79 | 0 | 0 | 0 | 0 | 0 | |||||||||||||||||||||
Deferred storm costs | 3 | 4 | 0 | 0 | 0 | 0 | 3 | 4 | |||||||||||||||||||||
Electric generation-related | |||||||||||||||||||||||||||||
regulatory asset | 13 | 33 | 0 | 0 | 0 | 0 | 13 | 33 | |||||||||||||||||||||
Rate stabilization deferral | 68 | 175 | 0 | 0 | 0 | 0 | 68 | 175 | |||||||||||||||||||||
Energy efficiency and demand | |||||||||||||||||||||||||||||
response programs | 75 | 144 | 0 | 0 | 0 | 0 | 75 | 144 | |||||||||||||||||||||
Merger integration costs (c) | 1 | 10 | 0 | 0 | 0 | 0 | 1 | 10 | |||||||||||||||||||||
Under-recovered electric | |||||||||||||||||||||||||||||
revenue decoupling (f) | 8 | 0 | 0 | 0 | 0 | 0 | 8 | 0 | |||||||||||||||||||||
Other | 48 | 26 | 34 | 13 | 13 | 7 | 1 | 5 | |||||||||||||||||||||
Total regulatory assets | $ | 877 | 6,509 | $ | 335 | $ | 819 | $ | 22 | $ | 1,419 | $ | 184 | $ | 509 | ||||||||||||||
30-Sep-13 | Exelon | ComEd | PECO | BGE | |||||||||||||||||||||||||
Regulatory liabilities | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | |||||||||||||||||||||
Nuclear decommissioning | $ | 0 | $ | 2,593 | $ | 0 | $ | 2,184 | $ | 0 | $ | 409 | $ | 0 | $ | 0 | |||||||||||||
Removal costs | 103 | 1,420 | 82 | 1,202 | 0 | 0 | 21 | 218 | |||||||||||||||||||||
Energy efficiency and demand | |||||||||||||||||||||||||||||
response programs | 85 | 0 | 49 | 0 | 36 | 0 | 0 | 0 | |||||||||||||||||||||
DLC Program Costs | 1 | 10 | 0 | 0 | 1 | 10 | 0 | 0 | |||||||||||||||||||||
Energy efficiency Phase 2 | 0 | 14 | 0 | 0 | 0 | 14 | 0 | 0 | |||||||||||||||||||||
Electric distribution tax repairs | 20 | 119 | 0 | 0 | 20 | 119 | 0 | 0 | |||||||||||||||||||||
Gas distribution tax repairs | 8 | 40 | 0 | 0 | 8 | 40 | 0 | 0 | |||||||||||||||||||||
Energy and transmission programs | 41 | 7 | 0 | 7 | 39 | (d) | 0 | 2 | (h) | 0 | |||||||||||||||||||
Over-recovered gas and electric | |||||||||||||||||||||||||||||
universal service fund costs | 7 | 0 | 0 | 0 | 7 | 0 | 0 | 0 | |||||||||||||||||||||
Revenue subject to refund (e) | 40 | 0 | 40 | 0 | 0 | 0 | 0 | 0 | |||||||||||||||||||||
Over-recovered gas | |||||||||||||||||||||||||||||
revenue decoupling (f) | 8 | 0 | 0 | 0 | 0 | 0 | 8 | 0 | |||||||||||||||||||||
Other | 1 | 1 | 0 | 0 | 0 | 0 | 0 | 0 | |||||||||||||||||||||
Total regulatory liabilities | $ | 314 | $ | 4,204 | $ | 171 | $ | 3,393 | $ | 111 | $ | 592 | $ | 31 | $ | 218 | |||||||||||||
31-Dec-12 | Exelon | ComEd | PECO | BGE | |||||||||||||||||||||||||
Regulatory assets | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | |||||||||||||||||||||
Pension and other postretirement | |||||||||||||||||||||||||||||
benefits | $ | 304 | $ | 3,673 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | |||||||||||||
Deferred income taxes | 14 | 1,382 | 5 | 62 | 0 | 1,255 | 9 | 65 | |||||||||||||||||||||
AMI programs | 3 | 70 | 3 | 10 | 0 | 29 | 0 | 31 | |||||||||||||||||||||
AMI meter events | 0 | 17 | 0 | 0 | 0 | 17 | 0 | 0 | |||||||||||||||||||||
Under-recovered distribution service | |||||||||||||||||||||||||||||
costs | 18 | 191 | 18 | 191 | 0 | 0 | 0 | 0 | |||||||||||||||||||||
Debt costs | 14 | 68 | 11 | 62 | 3 | 6 | 1 | 9 | |||||||||||||||||||||
Fair value of BGE long-term debt (a) | 0 | 256 | 0 | 0 | 0 | 0 | 0 | 0 | |||||||||||||||||||||
Fair value of BGE supply contract (b) | 77 | 12 | 0 | 0 | 0 | 0 | 0 | 0 | |||||||||||||||||||||
Severance | 29 | 28 | 25 | 12 | 0 | 0 | 4 | 16 | |||||||||||||||||||||
Asset retirement obligations | 0 | 90 | 0 | 65 | 0 | 25 | 0 | 0 | |||||||||||||||||||||
MGP remediation costs | 58 | 232 | 51 | 197 | 6 | 33 | 1 | 2 | |||||||||||||||||||||
RTO start-up costs | 3 | 2 | 3 | 2 | 0 | 0 | 0 | 0 | |||||||||||||||||||||
Under-recovered electric universal | |||||||||||||||||||||||||||||
service fund costs | 11 | 0 | 0 | 0 | 11 | 0 | 0 | 0 | |||||||||||||||||||||
Financial swap with Generation | 0 | 0 | 226 | 0 | 0 | 0 | 0 | 0 | |||||||||||||||||||||
Renewable energy and associated | |||||||||||||||||||||||||||||
RECs | 18 | 49 | 18 | 49 | 0 | 0 | 0 | 0 | |||||||||||||||||||||
Energy and transmission programs | 43 | 0 | 14 | 0 | 1 | (g) | 0 | 28 | (h) | 0 | |||||||||||||||||||
DSP Program costs | 1 | 3 | 0 | 0 | 1 | 3 | 0 | 0 | |||||||||||||||||||||
DSP II Program costs | 1 | 2 | 0 | 0 | 1 | 2 | 0 | 0 | |||||||||||||||||||||
Deferred storm costs | 3 | 6 | 0 | 0 | 0 | 0 | 3 | 6 | |||||||||||||||||||||
Electric generation-related | |||||||||||||||||||||||||||||
regulatory asset | 16 | 40 | 0 | 0 | 0 | 0 | 16 | 40 | |||||||||||||||||||||
Rate stabilization deferral | 67 | 225 | 0 | 0 | 0 | 0 | 67 | 225 | |||||||||||||||||||||
Energy efficiency and demand | |||||||||||||||||||||||||||||
response programs | 56 | 126 | 0 | 0 | 0 | 0 | 56 | 126 | |||||||||||||||||||||
Under-recovered electric | |||||||||||||||||||||||||||||
revenue decoupling (f) | 5 | 0 | 0 | 0 | 0 | 0 | 5 | 0 | |||||||||||||||||||||
Other | 23 | 25 | 14 | 16 | 9 | 8 | 0 | 2 | |||||||||||||||||||||
Total regulatory assets | $ | 764 | $ | 6,497 | $ | 388 | $ | 666 | $ | 32 | $ | 1,378 | $ | 190 | $ | 522 | |||||||||||||
31-Dec-12 | Exelon | ComEd | PECO | BGE | |||||||||||||||||||||||||
Regulatory liabilities | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | |||||||||||||||||||||
Nuclear decommissioning | $ | 0 | $ | 2,397 | $ | 0 | $ | 2,037 | $ | 0 | $ | 360 | $ | 0 | $ | 0 | |||||||||||||
Removal costs | 97 | 1,406 | 75 | 1,192 | 0 | 0 | 22 | 214 | |||||||||||||||||||||
Energy efficiency and demand | |||||||||||||||||||||||||||||
response programs | 131 | 0 | 43 | 0 | 88 | 0 | 0 | 0 | |||||||||||||||||||||
Electric distribution tax repairs | 20 | 132 | 0 | 0 | 20 | 132 | 0 | 0 | |||||||||||||||||||||
Gas distribution tax repairs | 8 | 46 | 0 | 0 | 8 | 46 | |||||||||||||||||||||||
Over-recovered uncollectible | |||||||||||||||||||||||||||||
accounts | 6 | 0 | 6 | 0 | 0 | 0 | 0 | 0 | |||||||||||||||||||||
Energy and transmission programs | 54 | 0 | 6 | 0 | 48 | (d) | 0 | 0 | 0 | ||||||||||||||||||||
Over-recovered gas universal | |||||||||||||||||||||||||||||
service fund costs | 3 | 0 | 0 | 0 | 3 | 0 | 0 | 0 | |||||||||||||||||||||
Over-recovered AEPS costs | 2 | 0 | 0 | 0 | 2 | 0 | 0 | 0 | |||||||||||||||||||||
Revenue subject to refund (e) | 40 | 0 | 40 | 0 | 0 | 0 | 0 | 0 | |||||||||||||||||||||
Over-recovered gas revenue | |||||||||||||||||||||||||||||
decoupling (f) | 7 | 0 | 0 | 0 | 0 | 0 | 7 | 0 | |||||||||||||||||||||
Total regulatory liabilities | $ | 368 | $ | 3,981 | $ | 170 | $ | 3,229 | $ | 169 | $ | 538 | $ | 29 | $ | 214 | |||||||||||||
Represents the regulatory asset recorded at Exelon Corporate for the difference in the fair value of the long-term debt of BGE as of the merger date. The asset is amortized over the life of the underlying debt. See Note 11 – Debt and Credit Agreements for additional information. | |||||||||||||||||||||||||||||
Represents the regulatory asset recorded at Exelon Corporate representing the fair value of BGE's supply contracts as of the close of the merger date. BGE is allowed full recovery of the costs of its electric and gas supply contracts through approved, regulated rates. The asset is amortized over a period of approximately 3 years. | |||||||||||||||||||||||||||||
ReIates to integration costs to achieve distribution synergies related to the merger transaction. | |||||||||||||||||||||||||||||
Includes $18 million related to the DSP program, $13 million related to the over-recovered natural gas costs under the PGC and $8 million related to over-recovered electric transmission costs as of September 30, 2013. As of December 31, 2012, includes $47 million related to the over-recovered electric supply costs under the GSA and $1 million related to the over-recovered natural gas costs under the PGC. | |||||||||||||||||||||||||||||
Primarily represents the regulatory liability for revenue subject to refund recorded pursuant to the ICC's order in the 2007 Rate Case. See above for discussion regarding the 2007 Rate Case. | |||||||||||||||||||||||||||||
Represents the electric and gas distribution costs recoverable from or refundable to customers under BGE's decoupling mechanism. | |||||||||||||||||||||||||||||
Relates to under-recovered transmission costs. | |||||||||||||||||||||||||||||
Relates to $2 million of over-recovered natural electric supply costs as of September 30, 2013. As of December 31, 2012, includes $9 million of under-recovered electric supply costs and $19 million of under-recovered natural gas supply costs. | |||||||||||||||||||||||||||||
As of September 30, 2013 | Exelon | ComEd | PECO | BGE | |||||||||||||||||||||||||
Purchased receivables (a) | $ | 285 | $ | 124 | $ | 78 | $ | 83 | |||||||||||||||||||||
Allowance for uncollectible accounts (b) | -31 | -18 | -7 | -6 | |||||||||||||||||||||||||
Purchased receivables, net | $ | 254 | $ | 106 | $ | 71 | $ | 77 | |||||||||||||||||||||
As of December 31, 2012 | Exelon | ComEd | PECO | BGE | |||||||||||||||||||||||||
Purchased receivables (a) | $ | 191 | $ | 55 | $ | 65 | $ | 71 | |||||||||||||||||||||
Allowance for uncollectible accounts (b) | -21 | -9 | -6 | -6 | |||||||||||||||||||||||||
Purchased receivables, net | $ | 170 | $ | 46 | $ | 59 | $ | 65 | |||||||||||||||||||||
__________ | |||||||||||||||||||||||||||||
(a) PECO's gas POR program became effective on January 1, 2012 and includes a 1% discount on purchased receivables in order to recover the implementation costs of the program. If the costs are not fully recovered when PECO files its next gas distribution rate case, PECO will propose a mechanism to recover the remaining implementation costs as a distribution charge to low volume transportation customers or apply future discounts on purchased receivables from natural gas suppliers serving those customers. | |||||||||||||||||||||||||||||
(b) For ComEd and BGE, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through its Purchase of Receivables with Consolidated Billing (PORCB) tariff. | |||||||||||||||||||||||||||||
Investment_in_Constellation_En1
Investment in Constellation Energy Nuclear Group, LLC (Tables) | 9 Months Ended | |||||||||||
Sep. 30, 2013 | ||||||||||||
Equity Method Investments and Joint Ventures Tables [Line Items] | ' | |||||||||||
Schedule of total equity in earnings of investment in CENG | ' | |||||||||||
Three Months | Three Months | |||||||||||
Ended September 30, | Ended September 30, | |||||||||||
2013 | 2012 | |||||||||||
Equity investment income | $ | 68 | $ | 58 | ||||||||
Amortization of basis difference in CENG | -31 | -57 | ||||||||||
Total equity in earnings - CENG | $ | 37 | $ | 1 | ||||||||
Nine Months | For the Period March 12, | |||||||||||
Ended September 30, | through September 30, | |||||||||||
2013 | 2012 | |||||||||||
Equity investment income (loss) | $ | 93 | $ | 53 | ||||||||
Amortization of basis difference in CENG | -88 | -131 | ||||||||||
Total equity in earnings (losses) - CENG | $ | 5 | $ | -78 | ||||||||
Schedule of summarized income statement information for CENG | ' | |||||||||||
Income/(Expense) | Income/(Expense) | Accounts | ||||||||||
Three Months | Nine Months | Income | Receivable/ | |||||||||
Ended | Ended | Statement | (Accounts Payable) | |||||||||
Agreement | 30-Sep-13 | 30-Sep-13 | Classification | At September 30, 2013 | ||||||||
PPA | $ | -269 | $ | -748 | Purchased power and fuel | $ | -76 | |||||
PSAA | 1 | 3 | Operating revenues | - | ||||||||
SSA | 10 | 32 | Operating revenues | 4 | ||||||||
Income/(Expense) | Income/(Expense) | Accounts | ||||||||||
Three Months | For the Period | Income | Receivable/ | |||||||||
Ended | March 12 through | Statement | (Accounts Payable) | |||||||||
Agreement | 30-Sep-12 | 30-Sep-12 | Classification | At September 30, 2012 | ||||||||
PPA | $ | -282 | $ | -541 | Purchased power and fuel | $ | -86 | |||||
PSAA | 1 | 2 | Operating revenues | - | ||||||||
SSA | 14 | 30 | Operating revenues | 5 | ||||||||
Exelon Generation Co L L C [Member] | ' | |||||||||||
Equity Method Investments and Joint Ventures Tables [Line Items] | ' | |||||||||||
Schedule of total equity in earnings of investment in CENG | ' | |||||||||||
Three Months | Three Months | |||||||||||
Ended September 30, | Ended September 30, | |||||||||||
2013 | 2012 | |||||||||||
Equity investment income | $ | 68 | $ | 58 | ||||||||
Amortization of basis difference in CENG | -31 | -57 | ||||||||||
Total equity in earnings - CENG | $ | 37 | $ | 1 | ||||||||
Nine Months | For the Period March 12, | |||||||||||
Ended September 30, | through September 30, | |||||||||||
2013 | 2012 | |||||||||||
Equity investment income (loss) | $ | 93 | $ | 53 | ||||||||
Amortization of basis difference in CENG | -88 | -131 | ||||||||||
Total equity in earnings (losses) - CENG | $ | 5 | $ | -78 | ||||||||
Schedule of summarized income statement information for CENG | ' | |||||||||||
Income/(Expense) | Income/(Expense) | Accounts | ||||||||||
Three Months | Nine Months | Income | Receivable/ | |||||||||
Ended | Ended | Statement | (Accounts Payable) | |||||||||
Agreement | 30-Sep-13 | 30-Sep-13 | Classification | At September 30, 2013 | ||||||||
PPA | $ | -269 | $ | -748 | Purchased power and fuel | $ | -76 | |||||
PSAA | 1 | 3 | Operating revenues | - | ||||||||
SSA | 10 | 32 | Operating revenues | 4 | ||||||||
Income/(Expense) | Income/(Expense) | Accounts | ||||||||||
Three Months | For the Period | Income | Receivable/ | |||||||||
Ended | March 12 through | Statement | (Accounts Payable) | |||||||||
Agreement | 30-Sep-12 | 30-Sep-12 | Classification | At September 30, 2012 | ||||||||
PPA | $ | -282 | $ | -541 | Purchased power and fuel | $ | -86 | |||||
PSAA | 1 | 2 | Operating revenues | - | ||||||||
SSA | 14 | 30 | Operating revenues | 5 |
Recovered_Sheet1
Impairment of Long-Lived assets (Tables) (Exelon Generation Co L L C [Member]) | 9 Months Ended | |||||
Sep. 30, 2013 | ||||||
Exelon Generation Co L L C [Member] | ' | |||||
Impaired Long-Lived Assets Held and Used [Line Items] | ' | |||||
Schedule of Capital Leased Assets [Table Text Block] | ' | |||||
30-Sep-13 | 31-Dec-12 | |||||
Estimated residual value of leased assets | $ | 1,465 | $ | 1,492 | ||
Less: unearned income | 774 | 807 | ||||
Net investment in long-term leases | $ | 691 | $ | 685 |
Fair_Value_of_Financial_Assets2
Fair Value of Financial Assets and Liabilities (Tables) | 9 Months Ended | ||||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||||
Fair Value Tables [Line Items] | ' | ||||||||||||||||||
Fair value of financial liabilities recorded at the carrying amount | ' | ||||||||||||||||||
30-Sep-13 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Short-term liabilities | $ | 217 | $ | 3 | $ | 214 | $ | 0 | $ | 217 | |||||||||
Long-term debt (including amounts due within one year) | 19,565 | 0 | 19,203 | 1,065 | 20,268 | ||||||||||||||
Long-term debt to financing trusts | 648 | 0 | 0 | 631 | 631 | ||||||||||||||
SNF obligation | 1,021 | 0 | 782 | 0 | 782 | ||||||||||||||
31-Dec-12 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Short-term liabilities | $ | 214 | $ | 4 | $ | 210 | $ | 0 | $ | 214 | |||||||||
Long-term debt (including amounts due within one year) | 18,745 | 0 | 20,244 | 276 | 20,520 | ||||||||||||||
Long-term debt to financing trusts | 648 | 0 | 0 | 664 | 664 | ||||||||||||||
SNF obligation | 1,020 | 0 | 763 | 0 | 763 | ||||||||||||||
Preferred securities of subsidiary | 87 | 0 | 82 | 0 | 82 | ||||||||||||||
Assets and liabilities measured and recorded at fair value on recurring basis | ' | ||||||||||||||||||
As of September 30, 2013 | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Assets | |||||||||||||||||||
Cash equivalents(a) | $ | 1 | $ | 0 | $ | 0 | $ | 1 | |||||||||||
Nuclear decommissioning trust fund investments | |||||||||||||||||||
Cash equivalents | 558 | 0 | 0 | 558 | |||||||||||||||
Equity | |||||||||||||||||||
Individually held | 1,600 | 0 | 0 | 1,600 | |||||||||||||||
Exchange traded funds | 110 | 0 | 0 | 110 | |||||||||||||||
Commingled funds | 0 | 2,114 | 0 | 2,114 | |||||||||||||||
Equity funds subtotal | 1,710 | 2,114 | 0 | 3,824 | |||||||||||||||
Fixed income | |||||||||||||||||||
Debt securities issued by the U.S. Treasury and other | |||||||||||||||||||
U.S. government corporations and agencies | 938 | 0 | 0 | 938 | |||||||||||||||
Debt securities issued by states of the United States | |||||||||||||||||||
and political subdivisions of the states | 0 | 295 | 0 | 295 | |||||||||||||||
Debt securities issued by foreign governments | 0 | 84 | 0 | 84 | |||||||||||||||
Corporate debt securities | 0 | 1,712 | 0 | 1,712 | |||||||||||||||
Federal agency mortgage-backed securities | 0 | 16 | 0 | 16 | |||||||||||||||
Commercial mortgage-backed securities (non-agency) | 0 | 41 | 0 | 41 | |||||||||||||||
Residential mortgage-backed securities (non-agency) | 0 | 7 | 0 | 7 | |||||||||||||||
Mutual funds | 0 | 29 | 0 | 29 | |||||||||||||||
Fixed income subtotal | 938 | 2,184 | 0 | 3,122 | |||||||||||||||
Middle market lending | 0 | 0 | 245 | 245 | |||||||||||||||
Other debt obligations | 0 | 14 | 0 | 14 | |||||||||||||||
Nuclear decommissioning trust fund investments subtotal(b) | 3,206 | 4,312 | 245 | 7,763 | |||||||||||||||
Pledged assets for Zion Station decommissioning | |||||||||||||||||||
Cash equivalents | 0 | 25 | 0 | 25 | |||||||||||||||
Equity | |||||||||||||||||||
Individually held | 4 | 0 | 0 | 4 | |||||||||||||||
Equity funds subtotal | 4 | 0 | 0 | 4 | |||||||||||||||
Fixed income | |||||||||||||||||||
Debt securities issued by the U.S. Treasury and other | |||||||||||||||||||
U.S. government corporations and agencies | 89 | 7 | 0 | 96 | |||||||||||||||
Debt securities issued by states of the United States | |||||||||||||||||||
and political subdivisions of the states | 0 | 24 | 0 | 24 | |||||||||||||||
Corporate debt securities | 0 | 217 | 0 | 217 | |||||||||||||||
Federal agency mortgage-backed securities | 0 | 7 | 0 | 7 | |||||||||||||||
Fixed income subtotal | 89 | 255 | 0 | 344 | |||||||||||||||
Middle market lending | 0 | 0 | 106 | 106 | |||||||||||||||
Pledged assets for Zion Station decommissioning subtotal(c) | 93 | 280 | 106 | 479 | |||||||||||||||
Rabbi trust investments | |||||||||||||||||||
Cash equivalents | 2 | 0 | 0 | 2 | |||||||||||||||
Mutual funds(d)(e) | 49 | 0 | 0 | 49 | |||||||||||||||
Rabbi trust investments subtotal | 51 | 0 | 0 | 51 | |||||||||||||||
Commodity derivative assets | |||||||||||||||||||
Economic hedges | 540 | 2,541 | 703 | 3,784 | |||||||||||||||
Proprietary trading | 666 | 1,184 | 174 | 2,024 | |||||||||||||||
Effect of netting and allocation of collateral(f) | -1,251 | -2,785 | -311 | -4,347 | |||||||||||||||
Commodity derivative assets subtotal | -45 | 940 | 566 | 1,461 | |||||||||||||||
Interest rate and foreign currency derivative assets | 34 | 49 | 0 | 83 | |||||||||||||||
Effect of netting and allocation of collateral | -33 | -2 | 0 | -35 | |||||||||||||||
Interest rate and foreign currency derivative assets subtotal | 1 | 47 | 0 | 48 | |||||||||||||||
Other investments | 1 | 0 | 11 | 12 | |||||||||||||||
Total assets | 3,308 | 5,579 | 928 | 9,815 | |||||||||||||||
Liabilities | |||||||||||||||||||
Commodity derivative liabilities | |||||||||||||||||||
Economic hedges | -764 | -1,718 | -363 | -2,845 | |||||||||||||||
Proprietary trading | -686 | -1,135 | -155 | -1,976 | |||||||||||||||
Effect of netting and allocation of collateral(f) | 1,359 | 2,843 | 291 | 4,493 | |||||||||||||||
Commodity derivative liabilities subtotal(h) | -91 | -10 | -227 | -328 | |||||||||||||||
Interest rate and foreign currency derivative liabilities | -34 | -17 | 0 | 0 | -51 | ||||||||||||||
Effect of netting and allocation of collateral | 33 | 2 | 0 | 35 | |||||||||||||||
Interest rate and foreign currency derivative liabilities subtotal | -1 | -15 | 0 | -16 | |||||||||||||||
Deferred compensation obligation | 0 | -108 | 0 | -108 | |||||||||||||||
Total liabilities | -92 | -133 | -227 | -452 | |||||||||||||||
Total net assets | $ | 3,216 | $ | 5,446 | $ | 701 | $ | 9,363 | |||||||||||
As of December 31, 2012 | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Assets | |||||||||||||||||||
Cash equivalents(a) | $ | 995 | $ | 0 | $ | 0 | $ | 995 | |||||||||||
Nuclear decommissioning trust fund investments | |||||||||||||||||||
Cash equivalents | 245 | 0 | 0 | 245 | |||||||||||||||
Equity | |||||||||||||||||||
Individually held | 1,480 | 0 | 0 | 1,480 | |||||||||||||||
Commingled funds | 0 | 1,933 | 0 | 1,933 | |||||||||||||||
Equity funds subtotal | 1,480 | 1,933 | 0 | 3,413 | |||||||||||||||
Fixed income | |||||||||||||||||||
Debt securities issued by the U.S. Treasury and other | |||||||||||||||||||
U.S. government corporations and agencies | 1,057 | 0 | 0 | 1,057 | |||||||||||||||
Debt securities issued by states of the United States | |||||||||||||||||||
and political subdivisions of the states | 0 | 321 | 0 | 321 | |||||||||||||||
Debt securities issued by foreign governments | 0 | 93 | 0 | 93 | |||||||||||||||
Corporate debt securities | 0 | 1,788 | 0 | 1,788 | |||||||||||||||
Federal agency mortgage-backed securities | 0 | 24 | 0 | 24 | |||||||||||||||
Commercial mortgage-backed securities (non-agency) | 0 | 45 | 0 | 45 | |||||||||||||||
Residential mortgage-backed securities (non-agency) | 0 | 11 | 0 | 11 | |||||||||||||||
Mutual funds | 0 | 23 | 0 | 23 | |||||||||||||||
Fixed income subtotal | 1,057 | 2,305 | 0 | 3,362 | |||||||||||||||
Middle market lending | 0 | 0 | 183 | 183 | |||||||||||||||
Other debt obligations | 0 | 15 | 0 | 15 | |||||||||||||||
Nuclear decommissioning trust fund investments subtotal(b) | 2,782 | 4,253 | 183 | 7,218 | |||||||||||||||
Pledged assets for Zion decommissioning | |||||||||||||||||||
Cash equivalents | 0 | 23 | 0 | 23 | |||||||||||||||
Equity | |||||||||||||||||||
Individually held | 14 | 0 | 0 | 14 | |||||||||||||||
Commingled funds | 0 | 9 | 0 | 9 | |||||||||||||||
Equity funds subtotal | 14 | 9 | 0 | 23 | |||||||||||||||
Fixed income | |||||||||||||||||||
Debt securities issued by the U.S. Treasury and other | |||||||||||||||||||
U.S. government corporations and agencies | 118 | 12 | 0 | 130 | |||||||||||||||
Debt securities issued by states of the United States | |||||||||||||||||||
and political subdivisions of the states | 0 | 37 | 0 | 37 | |||||||||||||||
Corporate debt securities | 0 | 249 | 0 | 249 | |||||||||||||||
Federal agency mortgage-backed securities | 0 | 49 | 0 | 49 | |||||||||||||||
Commercial mortgage-backed securities (non-agency) | 0 | 6 | 0 | 6 | |||||||||||||||
Fixed income subtotal | 118 | 353 | 0 | 471 | |||||||||||||||
Middle market lending | 0 | 0 | 89 | 89 | |||||||||||||||
Other debt obligations | 0 | 1 | 0 | 1 | |||||||||||||||
Pledged assets for Zion Station decommissioning subtotal(c) | 132 | 386 | 89 | 607 | |||||||||||||||
Rabbi trust investments | |||||||||||||||||||
Cash equivalents | 2 | 0 | 0 | 2 | |||||||||||||||
Mutual funds(d)(e) | 69 | 0 | 0 | 69 | |||||||||||||||
Rabbi trust investments subtotal | 71 | 0 | 0 | 71 | |||||||||||||||
Commodity derivative assets | |||||||||||||||||||
Economic hedges | 861 | 3,173 | 641 | 4,675 | |||||||||||||||
Proprietary trading | 1,042 | 2,078 | 73 | 3,193 | |||||||||||||||
Effect of netting and allocation of collateral(f) | -1,823 | -4,175 | -58 | -6,056 | |||||||||||||||
Commodity derivative assets subtotal(g) | 80 | 1,076 | 656 | 1,812 | |||||||||||||||
Interest rate and foreign currency derivative assets | 0 | 114 | 0 | 114 | |||||||||||||||
Effect of netting and allocation of collateral | 0 | -51 | 0 | -51 | |||||||||||||||
Interest rate and foreign currency derivative assets subtotal | 0 | 63 | 0 | 63 | |||||||||||||||
Other Investments | 2 | 0 | 17 | 19 | |||||||||||||||
Total assets | 4,062 | 5,778 | 945 | 10,785 | |||||||||||||||
Liabilities | |||||||||||||||||||
Commodity derivative liabilities | |||||||||||||||||||
Economic hedges | -1,041 | -2,289 | -236 | -3,566 | |||||||||||||||
Proprietary trading | -1,084 | -1,959 | -78 | -3,121 | |||||||||||||||
Effect of netting and allocation of collateral(f) | 2,042 | 4,020 | 25 | 6,087 | |||||||||||||||
Commodity derivative liabilities subtotal(g)(h) | -83 | -228 | -289 | -600 | |||||||||||||||
Interest rate and foreign currency derivative liabilities | 0 | -84 | 0 | -84 | |||||||||||||||
Effect of netting and allocation of collateral | 0 | 51 | 0 | 51 | |||||||||||||||
Interest rate and foreign currency derivative liabilities subtotal | 0 | -33 | 0 | -33 | |||||||||||||||
Deferred compensation obligation | 0 | -102 | 0 | -102 | |||||||||||||||
Total liabilities | -83 | -363 | -289 | -735 | |||||||||||||||
Total net assets | $ | 3,979 | $ | 5,415 | $ | 656 | $ | 10,050 | |||||||||||
(a) Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value. | |||||||||||||||||||
(b) Excludes net assets of $13 million and $30 million at September 30, 2013 and December 31, 2012, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases. | |||||||||||||||||||
(c) Excludes net assets of $7 million at both September 30, 2013 and December 31, 2012. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases. | |||||||||||||||||||
(d) The mutual funds held by the Rabbi trusts include $49 million related to deferred compensation at September 30, 2013, and $53 million related to deferred compensation and $16 million related to Supplemental Executive Retirement Plan at December 31, 2012. . | |||||||||||||||||||
(e) Excludes $30 million and $28 million of the cash surrender value of life insurance investments at September 30, 2013 and December 31, 2012, respectively. | |||||||||||||||||||
(f) Includes collateral postings (received) from counterparties. Collateral posted (received) from counterparties, net of collateral paid to counterparties, totaled $108 million, $58 million and $(20) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of September 30, 2013. Collateral posted (received) from counterparties, net of collateral paid to counterparties, totaled $219 million, $(155) million and $(33) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2012. | |||||||||||||||||||
(g) The Level 3 balance does not include current assets for Generation and current liabilities for ComEd of $226 million at December 31, 2012, related to the fair value of Generation's financial swap contract with ComEd. | |||||||||||||||||||
(h) The Level 3 balance includes the current and noncurrent liability of $16 million and $106 million at September 30, 2013, respectively, and $18 million and $49 million at December 31, 2012, respectively, related to floating-to-fixed energy swap contracts with unaffiliated suppliers. | |||||||||||||||||||
(f) The level 3 balance includes current assets for Generation of $226 million at December 31, 2012, related to the fair value of Generation's financial swap contract with ComEd, which eliminates upon consolidation in Exelon's Consolidated Financial Statements. | |||||||||||||||||||
Excludes $14 million and $13 million of the cash surrender value of life insurance investments at September 30, 2013 and December 31, 2012, respectively | |||||||||||||||||||
Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis | ' | ||||||||||||||||||
Three Months Ended September 30, 2013 | Nuclear Decommissioning Trust Fund Investments | Pledged Assets for Zion Station Decommissioning | Mark-to-Market Derivatives | Other Investments | Total | ||||||||||||||
Balance as of June 30, 2013 | $ | 240 | $ | 111 | $ | 431 | $ | 11 | $ | 793 | |||||||||
Total realized / unrealized losses | |||||||||||||||||||
Included in net income | 0 | 0 | -32 | (a) | 0 | -32 | |||||||||||||
Included in other comprehensive income | 0 | 0 | 0 | 0 | 0 | ||||||||||||||
Included in regulatory assets | -1 | 0 | -37 | 0 | -38 | ||||||||||||||
Included in payable for Zion Station decommissioning | 0 | 0 | 0 | 0 | 0 | ||||||||||||||
Change in collateral | 0 | 0 | -30 | 0 | -30 | ||||||||||||||
Purchases, sales, issuances and settlements | |||||||||||||||||||
Purchases | 23 | 10 | 8 | 0 | 41 | ||||||||||||||
Sales | -14 | -15 | 0 | 0 | -29 | ||||||||||||||
Settlements | -3 | 0 | 0 | 0 | -3 | ||||||||||||||
Transfers into Level 3 | 0 | 0 | 4 | 0 | 4 | ||||||||||||||
Transfers out of Level 3 | 0 | 0 | -5 | 0 | -5 | ||||||||||||||
Balance as of September 30, 2013 | $ | 245 | $ | 106 | $ | 339 | $ | 11 | $ | 701 | |||||||||
The amount of total gains included in income | |||||||||||||||||||
attributed to the change in unrealized gains related to assets and liabilities held for the three months ended September 30, 2013 | $ | 0 | $ | 0 | $ | 51 | $ | 0 | $ | 51 | |||||||||
Nine Months Ended September 30, 2013 | Nuclear Decommissioning Trust Fund Investments | Pledged Assets for Zion Station Decommissioning | Mark-to-Market Derivatives | Other Investments | Total | ||||||||||||||
Balance as of December 31, 2012 | $ | 183 | $ | 89 | $ | 367 | $ | 17 | $ | 656 | |||||||||
Total realized / unrealized gains (losses) | |||||||||||||||||||
Included in net income | 2 | 0 | -1 | (a) | 0 | 1 | |||||||||||||
Included in other comprehensive income | 0 | 0 | 0 | 0 | 0 | ||||||||||||||
Included in regulatory assets | 8 | 0 | -55 | (b) | 0 | -47 | |||||||||||||
Included in payable for Zion Station decommissioning | 0 | 1 | 0 | 0 | 1 | ||||||||||||||
Change in collateral | 0 | 0 | 13 | 0 | 13 | ||||||||||||||
Purchases, sales, issuances and settlements | |||||||||||||||||||
Purchases | 90 | 43 | 16 | 2 | 151 | ||||||||||||||
Sales | -27 | -27 | -8 | -8 | -70 | ||||||||||||||
Settlements | -11 | 0 | 0 | 0 | -11 | ||||||||||||||
Transfers into Level 3 | 0 | 0 | 11 | 0 | 11 | ||||||||||||||
Transfers out of Level 3 | 0 | 0 | -4 | 0 | -4 | ||||||||||||||
Balance as of September 30, 2013 | $ | 245 | $ | 106 | $ | 339 | $ | 11 | $ | 701 | |||||||||
The amount of total gains included in income | |||||||||||||||||||
attributed to the change in unrealized gains related to assets and liabilities held for the nine months ended September 30, 2013 | $ | 1 | $ | 0 | $ | 159 | $ | 0 | $ | 160 | |||||||||
(a) Includes the reclassification of $83 million and $160 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2013. | |||||||||||||||||||
(b) Excludes decreases in fair value of $11 million and realized losses reclassified due to settlements of $215 million associated with Generation's financial swap contract with ComEd for the nine months ended September 30, 2013. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements. | |||||||||||||||||||
Three Months Ended September 30, 2012 | Nuclear Decommissioning Trust Fund Investments | Pledged Assets for Zion Station Decommissioning | Mark-to-Market Derivatives | Other Investments | Total | ||||||||||||||
Balance as of June 30, 2012 | $ | 54 | $ | 59 | $ | 295 | $ | 17 | $ | 425 | |||||||||
Total realized / unrealized gains (losses) | |||||||||||||||||||
Included in net income | 0 | 0 | -97 | (a) | 0 | -97 | |||||||||||||
Included in other comprehensive income | 0 | 0 | 0 | 0 | 0 | ||||||||||||||
Included in regulatory assets | 2 | 0 | 41 | (b) | 0 | 43 | |||||||||||||
Included in payable for Zion Station | |||||||||||||||||||
decommissioning | 0 | 1 | 0 | 0 | 1 | ||||||||||||||
Change in collateral | 0 | 0 | -15 | 0 | -15 | ||||||||||||||
Purchases, sales, issuances and settlements | |||||||||||||||||||
Purchases | 14 | 4 | 0 | 0 | 18 | ||||||||||||||
Sales | 0 | 0 | 0 | 0 | 0 | ||||||||||||||
Transfers into Level 3 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||
Transfers out of Level 3 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||
Balance as of September 30, 2012 | $ | 70 | $ | 64 | $ | 224 | $ | 17 | $ | 375 | |||||||||
The amount of total losses included in income | |||||||||||||||||||
attributed to the change in unrealized losses related to assets and liabilities held for the three months ended September 30, 2012 | $ | 0 | $ | 0 | $ | -42 | $ | 0 | $ | -42 | |||||||||
Nine Months Ended September 30, 2012 | Nuclear Decommissioning Trust Fund Investments | Pledged Assets for Zion Decommissioning | Mark-to-Market Derivatives | Other Investments | Total | ||||||||||||||
Balance as of December 31, 2011 | $ | 13 | $ | 37 | $ | 17 | $ | 0 | $ | 67 | |||||||||
Total realized / unrealized gains (losses) | |||||||||||||||||||
Included in net income | 0 | 0 | -78 | (a) | 0 | -78 | |||||||||||||
Included in other comprehensive income | 0 | 0 | 0 | 0 | 0 | ||||||||||||||
Included in regulatory assets | 2 | 0 | 36 | (b) | 0 | 38 | |||||||||||||
Included in payable for Zion Station | |||||||||||||||||||
decommissioning | 0 | 0 | 0 | 0 | 0 | ||||||||||||||
Change in collateral | 0 | 0 | -7 | 0 | -7 | ||||||||||||||
Purchases, sales, issuances and settlements | |||||||||||||||||||
Purchases | 55 | 36 | 329 | (c) | 17 | 437 | |||||||||||||
Sales | 0 | -9 | 0 | 0 | -9 | ||||||||||||||
Transfers into Level 3 | 0 | 0 | -34 | 0 | -34 | ||||||||||||||
Transfers out of Level 3 | 0 | 0 | -39 | 0 | -39 | ||||||||||||||
Balance as of September 30, 2012 | $ | 70 | $ | 64 | $ | 224 | $ | 17 | $ | 375 | |||||||||
The amount of total gains included in income | |||||||||||||||||||
attributed to the change in unrealized gains related to assets and liabilities held for the nine months ended September 30, 2012 | $ | 0 | $ | 0 | $ | 62 | $ | 0 | $ | 62 | |||||||||
(a) Includes the reclassification of $55 million and $140 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2012, respectively. | |||||||||||||||||||
(b) Excludes $35 million of decreases in fair value and $86 million of increases in fair value and $119 million and $427 million of realized losses due to settlements for the three and nine months ended September 30, 2012 of Generation's financial swap contract with ComEd, which eliminates upon consolidation in Exelon's Consolidated Financial Statements. | |||||||||||||||||||
Total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis | ' | ||||||||||||||||||
Operating Revenue | Purchased Power and Fuel | Other, net (a) | |||||||||||||||||
Total gains (losses) included in income for the three months ended | |||||||||||||||||||
30-Sep-13 | $ | -39 | $ | 7 | $ | 0 | |||||||||||||
Total gains (losses) included in income for the nine months ended | |||||||||||||||||||
30-Sep-13 | $ | -61 | $ | 60 | $ | 2 | |||||||||||||
Change in the unrealized gains relating to assets and liabilities | |||||||||||||||||||
held for the three months ended September 30, 2013 | $ | 42 | $ | 9 | $ | 0 | |||||||||||||
Change in the unrealized gains relating to assets and liabilities | |||||||||||||||||||
held for the nine months ended September 30, 2013 | $ | 81 | $ | 78 | $ | 1 | |||||||||||||
Operating Revenue | Purchased Power and Fuel | Other, net | |||||||||||||||||
Total gains (losses) included in income for the three months | |||||||||||||||||||
ended September 30, 2012 | $ | -101 | $ | 4 | $ | 0 | |||||||||||||
Total losses included in income for the nine months ended | |||||||||||||||||||
30-Sep-12 | $ | -78 | $ | 0 | $ | 0 | |||||||||||||
Change in the unrealized gains (losses) relating to assets and | |||||||||||||||||||
liabilities held for the three months ended September 30, 2012 | $ | -43 | $ | 1 | $ | 0 | |||||||||||||
Change in the unrealized gains (losses) relating to assets and | |||||||||||||||||||
liabilities held for the nine months ended September 30, 2012 | $ | 82 | $ | -20 | $ | 0 | |||||||||||||
Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis, valuation technique | ' | ||||||||||||||||||
Type of trade | Fair Value at September 30, 2013 (c) | Valuation Technique | Unobservable Input | Range | |||||||||||||||
Mark-to-market derivatives – Economic Hedges (Generation) (a) | $ | 462 | Discounted Cash Flow | Forward power price | $ | 15 | - | $ | 103 | ||||||||||
Forward gas price | $ | 3.51 | - | $ | 5.97 | ||||||||||||||
Option Model | Volatility percentage | 27 | % | - | 107 | % | |||||||||||||
Mark-to-market derivatives – Proprietary trading (Generation) (a) | $ | 19 | Discounted Cash Flow | Forward power price | $ | 14 | - | $ | 103 | ||||||||||
Option Model | Volatility percentage | 14 | % | - | 28 | % | |||||||||||||
Mark-to-market derivatives (ComEd) | $ | -122 | Discounted Cash Flow | Forward heat rate (b) | 8 | - | 9 | ||||||||||||
Marketability reserve | 3.5 | % | - | 8 | % | ||||||||||||||
Renewable factor | 84 | % | - | 130 | % | ||||||||||||||
The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions. | |||||||||||||||||||
Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract's delivery. | |||||||||||||||||||
The fair values do not include cash collateral held on level three positions of $20 million as of September 30, 2013. | |||||||||||||||||||
Type of trade | Fair Value at December 31, 2012 (d) | Valuation Technique | Unobservable Input | Range | |||||||||||||||
Mark-to-market derivatives – Economic Hedges (Generation) (a) | $ | 473 | Discounted Cash Flow | Forward power price | $ | 14 | - | $ | 79 | ||||||||||
Forward gas price | $ | 3.26 | - | $ | 6.27 | ||||||||||||||
Option Model | Volatility percentage | 28 | % | - | 132 | % | |||||||||||||
Mark-to-market derivatives – Proprietary trading (Generation) (a) | $ | -6 | Discounted Cash Flow | Forward power price | $ | 15 | - | $ | 106 | ||||||||||
Option Model | Volatility percentage | 16 | % | - | 48 | % | |||||||||||||
Mark-to-market derivatives - Transactions with Affiliates (Generation and ComEd) (b) | $ | 226 | Discounted Cash Flow | Marketability reserve | 8 | % | - | 9 | % | ||||||||||
Mark-to-market derivatives (ComEd) | $ | -67 | Discounted Cash Flow | Forward heat rate (c) | 8 | - | 9.5 | ||||||||||||
Marketability reserve | 3.5 | % | - | 8.3 | % | ||||||||||||||
Renewable factor | 81 | % | - | 123 | % | ||||||||||||||
The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions. | |||||||||||||||||||
Includes current assets for Generation and current liabilities for ComEd of $226 million, related to the fair value of the five-year financial swap contract between Generation and ComEd, which eliminates in consolidation. | |||||||||||||||||||
Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract's delivery. | |||||||||||||||||||
The fair values do not include cash collateral held on level three positions of $33 million as of December 31, 2012. | |||||||||||||||||||
Exelon Generation Co L L C [Member] | ' | ||||||||||||||||||
Fair Value Tables [Line Items] | ' | ||||||||||||||||||
Fair value of financial liabilities recorded at the carrying amount | ' | ||||||||||||||||||
30-Sep-13 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Short-term liabilities | $ | 21 | $ | 0 | $ | 21 | $ | 0 | $ | 21 | |||||||||
Long-term debt (including amounts due within one year) | 7,809 | 0 | 6,744 | 1,047 | 7,791 | ||||||||||||||
SNF obligation | 1,021 | 0 | 782 | 0 | 782 | ||||||||||||||
31-Dec-12 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Long-term debt (including amounts due within one year) | $ | 7,483 | $ | 0 | $ | 7,591 | $ | 258 | $ | 7,849 | |||||||||
SNF obligation | 1,020 | 0 | 763 | 0 | 763 | ||||||||||||||
Assets and liabilities measured and recorded at fair value on recurring basis | ' | ||||||||||||||||||
As of September 30, 2013 | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Assets | |||||||||||||||||||
Cash equivalents | $ | 674 | $ | 0 | $ | 0 | $ | 674 | |||||||||||
Nuclear decommissioning trust fund investments | |||||||||||||||||||
Cash equivalents | 558 | 0 | 0 | 558 | |||||||||||||||
Equity | |||||||||||||||||||
Individually held | 1,600 | 0 | 0 | 1,600 | |||||||||||||||
Exchange traded funds | 110 | 0 | 0 | 110 | |||||||||||||||
Commingled funds | 0 | 2,114 | 0 | 2,114 | |||||||||||||||
Equity funds subtotal | 1,710 | 2,114 | 0 | 3,824 | |||||||||||||||
Fixed income | |||||||||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. | |||||||||||||||||||
government corporations and agencies | 938 | 0 | 0 | 938 | |||||||||||||||
Debt securities issued by states of the United States and | |||||||||||||||||||
political subdivisions of the states | 0 | 295 | 0 | 295 | |||||||||||||||
Debt securities issued by foreign governments | 0 | 84 | 0 | 84 | |||||||||||||||
Corporate debt securities | 0 | 1,712 | 0 | 1,712 | |||||||||||||||
Federal agency mortgage-backed securities | 0 | 16 | 0 | 16 | |||||||||||||||
Commercial mortgage-backed securities (non-agency) | 0 | 41 | 0 | 41 | |||||||||||||||
Residential mortgage-backed securities (non-agency) | 0 | 7 | 0 | 7 | |||||||||||||||
Mutual funds | 0 | 29 | 0 | 29 | |||||||||||||||
Fixed income subtotal | 938 | 2,184 | 0 | 3,122 | |||||||||||||||
Middle market lending | 0 | 0 | 245 | 245 | |||||||||||||||
Other debt obligations | 0 | 14 | 0 | 14 | |||||||||||||||
Nuclear decommissioning trust fund investments subtotal(b) | 3,206 | 4,312 | 245 | 7,763 | |||||||||||||||
Pledged assets for Zion Station decommissioning | |||||||||||||||||||
Cash equivalents | 0 | 25 | 0 | 25 | |||||||||||||||
Equity | |||||||||||||||||||
Individually held | 4 | 0 | 0 | 4 | |||||||||||||||
Equity funds subtotal | 4 | 0 | 0 | 4 | |||||||||||||||
Fixed income | |||||||||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. | |||||||||||||||||||
government corporations and agencies | 89 | 7 | 0 | 96 | |||||||||||||||
Debt securities issued by states of the United States and | |||||||||||||||||||
political subdivisions of the states | 0 | 24 | 0 | 24 | |||||||||||||||
Corporate debt securities | 0 | 217 | 0 | 217 | |||||||||||||||
Federal agency mortgage-backed securities | 0 | 7 | 0 | 7 | |||||||||||||||
Fixed income subtotal | 89 | 255 | 0 | 344 | |||||||||||||||
Middle market lending | 0 | 0 | 106 | 106 | |||||||||||||||
Pledged assets for Zion Station decommissioning subtotal(c) | 93 | 280 | 106 | 479 | |||||||||||||||
Rabbi trust investments | |||||||||||||||||||
Mutual funds(d) | 12 | 0 | 0 | 12 | |||||||||||||||
Rabbi trust investments subtotal | 12 | 0 | 0 | 12 | |||||||||||||||
Commodity derivative assets | |||||||||||||||||||
Economic hedges | 540 | 2,541 | 703 | 3,784 | |||||||||||||||
Proprietary trading | 666 | 1,184 | 174 | 2,024 | |||||||||||||||
Effect of netting and allocation of collateral(e) | -1,251 | -2,785 | -311 | -4,347 | |||||||||||||||
Commodity derivative assets subtotal | -45 | 940 | 566 | 1,461 | |||||||||||||||
Interest rate and foreign currency derivative assets | 34 | 36 | 0 | 70 | |||||||||||||||
Effect of netting and allocation of collateral | -33 | -2 | 0 | -35 | |||||||||||||||
Interest rate and foreign currency derivative assets subtotal | 1 | 34 | 0 | 35 | |||||||||||||||
Other investments | 1 | 0 | 11 | 12 | |||||||||||||||
Total assets | 3,942 | 5,566 | 928 | 10,436 | |||||||||||||||
Liabilities | |||||||||||||||||||
Commodity derivative liabilities | |||||||||||||||||||
Economic hedges | -764 | -1,718 | -241 | -2,723 | |||||||||||||||
Proprietary trading | -686 | -1,135 | -155 | -1,976 | |||||||||||||||
Effect of netting and allocation of collateral(e) | 1,359 | 2,843 | 291 | 4,493 | |||||||||||||||
Commodity derivative liabilities subtotal | -91 | -10 | -105 | -206 | |||||||||||||||
Interest rate and foreign currency derivative liabilities | -34 | -17 | 0 | -51 | |||||||||||||||
Effect of netting and allocation of collateral | 33 | 2 | 0 | 35 | |||||||||||||||
Interest rate and foreign currency derivative liabilities subtotal | -1 | -15 | 0 | -16 | |||||||||||||||
Deferred compensation obligation | 0 | -27 | 0 | -27 | |||||||||||||||
Total liabilities | -92 | -52 | -105 | -249 | |||||||||||||||
Total net assets | $ | 3,850 | $ | 5,514 | $ | 823 | $ | 10,187 | |||||||||||
As of December 31, 2012 | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Assets | |||||||||||||||||||
Cash equivalents(a) | $ | 487 | $ | 0 | $ | 0 | $ | 487 | |||||||||||
Nuclear decommissioning trust fund investments | |||||||||||||||||||
Cash equivalents | 245 | 0 | 0 | 245 | |||||||||||||||
Equity | |||||||||||||||||||
Individually held | 1,480 | 0 | 0 | 1,480 | |||||||||||||||
Commingled funds | 0 | 1,933 | 0 | 1,933 | |||||||||||||||
Equity funds subtotal | 1,480 | 1,933 | 0 | 3,413 | |||||||||||||||
Fixed income | |||||||||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. | |||||||||||||||||||
government corporations and agencies | 1,057 | 0 | 0 | 1,057 | |||||||||||||||
Debt securities issued by states of the United States and | |||||||||||||||||||
political subdivisions of the states | 0 | 321 | 0 | 321 | |||||||||||||||
Debt securities issued by foreign governments | 0 | 93 | 0 | 93 | |||||||||||||||
Corporate debt securities | 0 | 1,788 | 0 | 1,788 | |||||||||||||||
Federal agency mortgage-backed securities | 0 | 24 | 0 | 24 | |||||||||||||||
Commercial mortgage-backed securities (non-agency) | 0 | 45 | 0 | 45 | |||||||||||||||
Residential mortgage-backed securities (non-agency) | 0 | 11 | 0 | 11 | |||||||||||||||
Mutual funds | 0 | 23 | 0 | 23 | |||||||||||||||
Fixed income subtotal | 1,057 | 2,305 | 0 | 3,362 | |||||||||||||||
Middle market lending | 0 | 0 | 183 | 183 | |||||||||||||||
Other debt obligations | 0 | 15 | 0 | 15 | |||||||||||||||
Nuclear decommissioning trust fund investments subtotal(b) | 2,782 | 4,253 | 183 | 7,218 | |||||||||||||||
Pledged assets for Zion Station decommissioning | |||||||||||||||||||
Cash equivalents | 0 | 23 | 0 | 23 | |||||||||||||||
Equity | |||||||||||||||||||
Individually held | 14 | 0 | 0 | 14 | |||||||||||||||
Commingled funds | 0 | 9 | 0 | 9 | |||||||||||||||
Equity funds subtotal | 14 | 9 | 0 | 23 | |||||||||||||||
Fixed income | |||||||||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. | |||||||||||||||||||
government corporations and agencies | 118 | 12 | 0 | 130 | |||||||||||||||
Debt securities issued by states of the United States and | |||||||||||||||||||
political subdivisions of the states | 0 | 37 | 0 | 37 | |||||||||||||||
Corporate debt securities | 0 | 249 | 0 | 249 | |||||||||||||||
Federal agency mortgage-backed securities | 0 | 49 | 0 | 49 | |||||||||||||||
Commercial mortgage-backed securities (non-agency) | 0 | 6 | 0 | 6 | |||||||||||||||
Fixed income subtotal | 118 | 353 | 0 | 471 | |||||||||||||||
Middle market lending | 0 | 0 | 89 | 89 | |||||||||||||||
Other debt obligations | 0 | 1 | 0 | 1 | |||||||||||||||
Pledged assets for Zion Station decommissioning subtotal(c) | 132 | 386 | 89 | 607 | |||||||||||||||
Rabbi trust investments | |||||||||||||||||||
Cash equivalents | 1 | 0 | 0 | 1 | |||||||||||||||
Mutual funds(d) | 13 | 0 | 0 | 13 | |||||||||||||||
Rabbi trust investments subtotal | 14 | 0 | 0 | 14 | |||||||||||||||
Commodity derivative assets | |||||||||||||||||||
Economic hedges | 861 | 3,173 | 867 | 4,901 | |||||||||||||||
Proprietary trading | 1,042 | 2,078 | 73 | 3,193 | |||||||||||||||
Effect of netting and allocation of collateral(e) | -1,823 | -4,175 | -58 | -6,056 | |||||||||||||||
Commodity and foreign currency assets subtotal(f) | 80 | 1,076 | 882 | 2,038 | |||||||||||||||
Interest rate and foreign currency derivative assets | 0 | 101 | 0 | 101 | |||||||||||||||
Effect of netting and allocation of collateral | 0 | -51 | 0 | -51 | |||||||||||||||
Interest rate and foreign currency derivative assets subtotal | 0 | 50 | 0 | 50 | |||||||||||||||
Other investments | 2 | 0 | 17 | 19 | |||||||||||||||
Total assets | 3,497 | 5,765 | 1,171 | 10,433 | |||||||||||||||
Liabilities | |||||||||||||||||||
Commodity derivative liabilities | |||||||||||||||||||
Economic hedges | -1,041 | -2,289 | -169 | -3,499 | |||||||||||||||
Proprietary trading | -1,084 | -1,959 | -78 | -3,121 | |||||||||||||||
Effect of netting and allocation of collateral(e) | 2,042 | 4,020 | 25 | 6,087 | |||||||||||||||
Commodity derivative liabilities subtotal | -83 | -228 | -222 | -533 | |||||||||||||||
Interest rate derivative liabilities | 0 | -84 | 0 | -84 | |||||||||||||||
Effect of netting and allocation of collateral | 0 | 51 | 0 | 51 | |||||||||||||||
Interest rate and foreign currency derivative liabilities | 0 | -33 | 0 | -33 | |||||||||||||||
Deferred compensation obligation | 0 | -28 | 0 | -28 | |||||||||||||||
Total liabilities | -83 | -289 | -222 | -594 | |||||||||||||||
Total net assets | $ | 3,414 | $ | 5,476 | $ | 949 | $ | 9,839 | |||||||||||
(a) Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value. | |||||||||||||||||||
(b) Excludes net assets of $13 million and $30 million at September 30, 2013 and December 31, 2012, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases. | |||||||||||||||||||
(c) Excludes net assets of $7 at both September 30, 2013 December 31, 2012. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases. | |||||||||||||||||||
(d) Excludes $9 million and $8 million of the cash surrender value of life insurance investments at September 30, 2013 and December 31, 2012, respectively. | |||||||||||||||||||
(e) Includes collateral postings (received) from counterparties. Collateral posted (received) from counterparties, net of collateral paid to counterparties, totaled $108 million, $58 million and $(20) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of September 30, 2013. Collateral posted (received) from counterparties, net of collateral paid to counterparties, totaled $219 million, $(155) million and $(33) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2012. | |||||||||||||||||||
Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis | ' | ||||||||||||||||||
Three Months Ended September 30, 2013 | Nuclear Decommissioning Trust Fund Investments | Pledged Assets for Zion Station Decommissioning | Mark-to-Market Derivatives | Other Investments | Total | ||||||||||||||
Balance as of June 30, 2013 | $ | 240 | $ | 111 | $ | 516 | $ | 11 | $ | 878 | |||||||||
Total realized / unrealized gains (losses) | |||||||||||||||||||
Included in net income | 0 | 0 | -32 | (a) | 0 | -32 | |||||||||||||
Included in noncurrent payables to affiliates | -1 | 0 | 0 | 0 | -1 | ||||||||||||||
Change in collateral | 0 | 0 | -30 | 0 | -30 | ||||||||||||||
Purchases, sales, issuances and settlements | |||||||||||||||||||
Purchases | 23 | 10 | 8 | 0 | 41 | ||||||||||||||
Sales | -14 | -15 | 0 | 0 | -29 | ||||||||||||||
Settlements | -3 | 0 | 0 | 0 | -3 | ||||||||||||||
Transfers into Level 3 | 0 | 0 | 4 | 0 | 4 | ||||||||||||||
Transfers out of Level 3 | 0 | 0 | -5 | 0 | -5 | ||||||||||||||
Balance as of September 30, 2013 | $ | 245 | $ | 106 | $ | 461 | $ | 11 | $ | 823 | |||||||||
The amount of total gains included in income | |||||||||||||||||||
attributed to the change in unrealized gains related to assets and liabilities held for the three months ended September 30, 2013 | $ | 0 | $ | 0 | $ | 51 | $ | 0 | $ | 51 | |||||||||
Nine Months Ended September 30, 2013 | Nuclear Decommissioning Trust Fund Investments | Pledged Assets for Zion Station Decommissioning | Mark-to-Market Derivatives | Other Investments | Total | ||||||||||||||
Balance as of December 31, 2012 | $ | 183 | $ | 89 | $ | 660 | $ | 17 | $ | 949 | |||||||||
Total realized / unrealized gains (losses) | |||||||||||||||||||
Included in net income | 2 | 0 | -8 | (a)(b) | 0 | -6 | |||||||||||||
Included in other comprehensive income | 0 | 0 | -219 | (b) | 0 | -219 | |||||||||||||
Included in noncurrent payables to affiliates | 8 | 0 | 0 | 0 | 8 | ||||||||||||||
Included in payable for Zion Station decommissioning | 0 | 1 | 0 | 0 | 1 | ||||||||||||||
Change in collateral | 0 | 13 | 0 | 13 | |||||||||||||||
Purchases, sales, issuances and settlements | |||||||||||||||||||
Purchases | 90 | 43 | 16 | 2 | 151 | ||||||||||||||
Sales | -27 | -27 | -8 | -8 | -70 | ||||||||||||||
Settlements | -11 | 0 | 0 | 0 | -11 | ||||||||||||||
Transfers into Level 3 | 0 | 0 | 11 | 11 | |||||||||||||||
Transfers out of Level 3 | 0 | 0 | -4 | 0 | -4 | ||||||||||||||
Balance as of September 30, 2013 | $ | 245 | $ | 106 | $ | 461 | $ | 11 | $ | 823 | |||||||||
The amount of total gains included in income | |||||||||||||||||||
attributed to the change in unrealized gains related to assets and liabilities held for the nine months ended September 30, 2013 | $ | 1 | $ | 0 | $ | 148 | $ | 0 | $ | 149 | |||||||||
(a) Includes the reclassification of $83 million and $156 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2013, respectively. | |||||||||||||||||||
(b) Includes $11 million of increases in fair value and realized losses due to settlements of $215 million associated with Generation's financial swap contract with ComEd for the nine months ended September 30, 2013. This position eliminates upon consolidation in Exelon's Consolidated Financial Statements. | |||||||||||||||||||
Three Months Ended September 30, 2012 | Nuclear Decommissioning Trust Fund Investments | Pledged Assets for Zion Station Decommissioning | Mark-to-Market Derivatives | Other Investments | Total | ||||||||||||||
Balance as of June 30, 2012 | $ | 54 | $ | 59 | $ | 912 | $ | 17 | $ | 1,042 | |||||||||
Total realized / unrealized gains (losses) | |||||||||||||||||||
Included in net income | 0 | 0 | -112 | (a) | 0 | -112 | |||||||||||||
Included in other comprehensive income | 0 | 0 | -139 | (b) | 0 | -139 | |||||||||||||
Included in noncurrent payables to affiliates | 2 | 0 | 0 | 0 | 2 | ||||||||||||||
Included in payable for Zion Station decommissioning | 0 | 1 | 0 | 0 | 1 | ||||||||||||||
Changes in collateral | 0 | 0 | -15 | 0 | -15 | ||||||||||||||
Purchases, sales, issuances and settlements | |||||||||||||||||||
Purchases | 14 | 4 | 0 | 0 | 18 | ||||||||||||||
Sales | 0 | 0 | 0 | 0 | 0 | ||||||||||||||
Balance as of September 30, 2012 | $ | 70 | $ | 64 | $ | 646 | $ | 17 | $ | 797 | |||||||||
The amount of total losses included in income | |||||||||||||||||||
attributed to the change in unrealized losses related to assets and liabilities held for the three months ended September 30, 2012 | $ | 0 | $ | 0 | $ | -77 | $ | 0 | $ | -77 | |||||||||
Nine Months Ended September 30, 2012 | Nuclear Decommissioning Trust Fund Investments | Pledged Assets for Zion Station Decommissioning | Mark-to-Market Derivatives | Other Investments | Total | ||||||||||||||
Balance as of December 31, 2011 | $ | 13 | $ | 37 | $ | 817 | $ | 0 | $ | 867 | |||||||||
Total realized / unrealized gains (losses) | |||||||||||||||||||
Included in net income | 0 | 0 | -109 | (a) | 0 | -109 | |||||||||||||
Included in other comprehensive income | 0 | 0 | -311 | (b) | 0 | -311 | |||||||||||||
Included in noncurrent payables to affiliates | 2 | 0 | 0 | 2 | |||||||||||||||
Changes in collateral | 0 | 0 | -7 | 0 | -7 | ||||||||||||||
Purchases, sales, issuances and settlements | 0 | ||||||||||||||||||
Purchases | 55 | 36 | 329 | (c) | 17 | 437 | |||||||||||||
Sales | 0 | -9 | 0 | 0 | -9 | ||||||||||||||
Transfers into Level 3 | 0 | 0 | -34 | 0 | -34 | ||||||||||||||
Transfers out of Level 3 | 0 | 0 | -39 | 0 | -39 | ||||||||||||||
Balance as of September 30, 2012 | $ | 70 | $ | 64 | $ | 646 | $ | 17 | $ | 797 | |||||||||
The amount of total gains included in income | |||||||||||||||||||
attributed to the change in unrealized gains related to assets and liabilities held for the nine months ended September 30, 2012 | $ | 0 | $ | 0 | $ | 1 | $ | 0 | $ | 1 | |||||||||
(a) Includes the reclassification of $35 million and $110 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2012, respectively. | |||||||||||||||||||
(b) Includes $35 million of decreases in fair value and $86 million of increases in fair value and realized losses due to settlements of $119 million and $427 million associated with Generation's financial swap contract with ComEd for the three and nine months ended September 30, 2012, respectively. This position was re-designated as a cash flow hedge prior to the merger date. All prospective changes in fair value and reclassifications of realized amounts are being recorded to income offset by the amortization of the frozen mark in OCI. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements. | |||||||||||||||||||
(c) Includes $310 million of fair value from contracts and $14 million of other investments acquired as a result of the merger. | |||||||||||||||||||
Total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis | ' | ||||||||||||||||||
(a) Other, net activity consists of realized and unrealized gains (losses) included in income for the NDT funds held by Generation. | |||||||||||||||||||
Operating Revenue | Purchased Power and Fuel | Other, net (a) | |||||||||||||||||
Total gains (losses) included in net income for the three months | $ | -39 | $ | 7 | $ | 0 | |||||||||||||
ended September 30, 2013 | |||||||||||||||||||
Total gains (losses) included in net income for the nine months | |||||||||||||||||||
ended September 30, 2013 | $ | -67 | $ | 59 | $ | 2 | |||||||||||||
Change in the unrealized gains relating to assets and liabilities | |||||||||||||||||||
held for the three months ended September 30, 2013 | $ | 42 | $ | 9 | $ | 0 | |||||||||||||
Change in the unrealized gains relating to assets and liabilities | |||||||||||||||||||
held for the nine months ended September 30, 2013 | $ | 71 | $ | 77 | $ | 1 | |||||||||||||
Operating Revenue | Purchased Power and Fuel | Other, net | |||||||||||||||||
Total gains (losses) included in net income for the three months | $ | -116 | $ | 4 | $ | 0 | |||||||||||||
ended September 30, 2012 | |||||||||||||||||||
Total losses included in net income for the nine months | $ | -109 | $ | 0 | $ | 0 | |||||||||||||
ended September 30, 2012 | |||||||||||||||||||
Change in the unrealized gains (losses) relating to assets and | $ | -78 | $ | 1 | $ | 0 | |||||||||||||
liabilities held for the three months ended September 30, 2012 | |||||||||||||||||||
Change in the unrealized gains (losses) relating to assets and | $ | 21 | $ | -20 | $ | 0 | |||||||||||||
liabilities held for the nine months ended September 30, 2012 | |||||||||||||||||||
(a) Other, net activity consists of realized and unrealized gains (losses) included in income for the NDT funds held by Generation. | |||||||||||||||||||
Commonwealth Edison Co [Member] | ' | ||||||||||||||||||
Fair Value Tables [Line Items] | ' | ||||||||||||||||||
Fair value of financial liabilities recorded at the carrying amount | ' | ||||||||||||||||||
30-Sep-13 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Short-term liabilities | $ | 153 | $ | 0 | $ | 153 | $ | 0 | $ | 153 | |||||||||
Long-term debt (including amounts due within one year) | 5,674 | 0 | 6,240 | 17 | 6,257 | ||||||||||||||
Long-term debt to financing trust | 206 | 0 | 0 | 195 | 195 | ||||||||||||||
31-Dec-12 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Long-term debt (including amounts due within one year) | $ | 5,567 | $ | 0 | $ | 6,530 | $ | 18 | $ | 6,548 | |||||||||
Long-term debt to financing trust | 206 | 0 | 0 | 212 | 212 | ||||||||||||||
Assets and liabilities measured and recorded at fair value on recurring basis | ' | ||||||||||||||||||
As of September 30, 2013 | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Assets | |||||||||||||||||||
Cash equivalents | $ | 0 | $ | 0 | $ | 0 | $ | 0 | |||||||||||
Rabbi trust investments | |||||||||||||||||||
Mutual funds | 5 | 0 | 0 | 5 | |||||||||||||||
Rabbi trust investments subtotal | 5 | 0 | 0 | 5 | |||||||||||||||
Total assets | 5 | 0 | 0 | 5 | |||||||||||||||
Liabilities | |||||||||||||||||||
Deferred compensation obligation | 0 | -8 | 0 | -8 | |||||||||||||||
Mark-to-market derivative liabilities(a) | 0 | 0 | -122 | -122 | |||||||||||||||
Total liabilities | 0 | -8 | -122 | -130 | |||||||||||||||
Total net assets (liabilities) | $ | 5 | $ | -8 | $ | -122 | $ | -125 | |||||||||||
As of December 31, 2012 | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Assets | |||||||||||||||||||
Cash equivalents | $ | 111 | $ | 0 | $ | 0 | $ | 111 | |||||||||||
Rabbi trust investments | |||||||||||||||||||
Mutual funds | 8 | 0 | 0 | 8 | |||||||||||||||
Rabbi trust investments subtotal | 8 | 0 | 0 | 8 | |||||||||||||||
Total assets | 119 | 0 | 0 | 119 | |||||||||||||||
Liabilities | |||||||||||||||||||
Deferred compensation obligation | 0 | -8 | 0 | -8 | |||||||||||||||
Mark-to-market derivative liabilities(a)(b) | 0 | 0 | -293 | -293 | |||||||||||||||
Total liabilities | 0 | -8 | -293 | -301 | |||||||||||||||
Total net assets (liabilities) | $ | 119 | $ | -8 | $ | -293 | $ | -182 | |||||||||||
(a) The Level 3 balance includes the current and noncurrent liability of $16 million and $106 million at September 30, 2013, respectively, and $18 million and $49 million at December 31, 2012, respectively, related to floating-to-fixed energy swap contracts with unaffiliated suppliers. | |||||||||||||||||||
(b) The Level 3 balance includes the current liability of $226 million at December 31, 2012, related to the fair value of ComEd's financial swap contract with Generation which eliminated 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 | ' | ||||||||||||||||||
Three Months Ended September 30, 2013 | Mark-to-Market Derivatives | ||||||||||||||||||
Balance as of June 30, 2013 | $ | -85 | |||||||||||||||||
Total realized / unrealized gains included in regulatory assets(b) | -37 | ||||||||||||||||||
Balance as of September 30, 2013 | $ | -122 | |||||||||||||||||
Nine Months Ended September 30, 2013 | Mark-to-Market Derivatives | ||||||||||||||||||
Balance as of December 31, 2012 | $ | -293 | |||||||||||||||||
Total realized / unrealized gains included in regulatory assets(a)(b) | 171 | ||||||||||||||||||
Balance as of September 30, 2013 | $ | -122 | |||||||||||||||||
(a) Includes $11 million of decreases in fair value and realized gains due to settlements of $215 million associated with ComEd's financial swap contract with Generation for the nine months ended September 30, 2013. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements. | |||||||||||||||||||
(b) Includes $37 million and $57 million of increases in the fair value and realized losses due to settlements of $1 million and $5 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three and nine months ended September 30, 2013, respectively. | |||||||||||||||||||
Three Months Ended September 30, 2012 | Mark-to-Market Derivatives | ||||||||||||||||||
Balance as of June 30, 2012 | $ | -617 | |||||||||||||||||
Total realized / unrealized gains included in regulatory assets(a)(b) | 195 | ||||||||||||||||||
Balance as of September 30, 2012 | $ | -422 | |||||||||||||||||
Nine Months Ended September 30, 2012 | Mark-to-Market Derivatives | ||||||||||||||||||
Balance as of December 31, 2011 | $ | -800 | |||||||||||||||||
Total realized / unrealized gains included in regulatory assets(a)(b) | 378 | ||||||||||||||||||
Balance as of September 30, 2012 | $ | -422 | |||||||||||||||||
Total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis | ' | ||||||||||||||||||
Includes $35 million of increases in fair value and $86 million of decreases in fair value and realized gains due to settlements of $119 million and $427 million of associated with ComEd's financial swap contract with Generation for the three and nine months ended September 30, 2012, respectively. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements. | |||||||||||||||||||
Includes $40 million and $33 million of increases in the fair value and realized losses due to settlements of $1 million and $2 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three and nine months ended September 30, 2012, respectively. | |||||||||||||||||||
PECO Energy Co [Member] | ' | ||||||||||||||||||
Fair Value Tables [Line Items] | ' | ||||||||||||||||||
Fair value of financial liabilities recorded at the carrying amount | ' | ||||||||||||||||||
30-Sep-13 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Long-term debt (including amounts due within one year) | $ | 2,496 | $ | 0 | $ | 2,678 | $ | 0 | $ | 2,678 | |||||||||
Long-term debt to financing trusts | 184 | 0 | 0 | 182 | 182 | ||||||||||||||
31-Dec-12 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Short-term liabilities | $ | 210 | $ | 0 | $ | 210 | $ | 0 | $ | 210 | |||||||||
Long-term debt (including amounts due within one year) | 1,947 | 0 | 2,264 | 0 | 2,264 | ||||||||||||||
Long-term debt to financing trusts | 184 | 0 | 0 | 188 | 188 | ||||||||||||||
Preferred securities | 87 | 0 | 82 | 0 | 82 | ||||||||||||||
Assets and liabilities measured and recorded at fair value on recurring basis | ' | ||||||||||||||||||
As of September 30, 2013 | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Assets | |||||||||||||||||||
Cash equivalents | $ | 583 | $ | 0 | $ | 0 | $ | 583 | |||||||||||
Rabbi trust investments | |||||||||||||||||||
Mutual funds(a) | 9 | 0 | 0 | 9 | |||||||||||||||
Rabbi trust investments subtotal | 9 | 0 | 0 | 9 | |||||||||||||||
Total assets | 592 | 0 | 0 | 592 | |||||||||||||||
Liabilities | |||||||||||||||||||
Deferred compensation obligation | 0 | -16 | 0 | -16 | |||||||||||||||
Total liabilities | 0 | -16 | 0 | -16 | |||||||||||||||
Total net assets (liabilities) | $ | 592 | $ | -16 | $ | 0 | $ | 576 | |||||||||||
As of December 31, 2012 | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Assets | |||||||||||||||||||
Cash equivalents | $ | 346 | $ | 0 | $ | 0 | $ | 346 | |||||||||||
Rabbi trust investments | |||||||||||||||||||
Mutual funds(a) | 9 | 0 | 0 | 9 | |||||||||||||||
Rabbi trust investments subtotal | 9 | 0 | 0 | 9 | |||||||||||||||
Total assets | 355 | 0 | 0 | 355 | |||||||||||||||
Liabilities | |||||||||||||||||||
Deferred compensation obligation | 0 | -18 | 0 | -18 | |||||||||||||||
Total liabilities | 0 | -18 | 0 | -18 | |||||||||||||||
Total net assets (liabilities) | $ | 355 | $ | -18 | $ | 0 | $ | 337 | |||||||||||
Baltimore Gas and Electric Company [Member] | ' | ||||||||||||||||||
Fair Value Tables [Line Items] | ' | ||||||||||||||||||
Fair value of financial liabilities recorded at the carrying amount | ' | ||||||||||||||||||
30-Sep-13 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Short-term liabilities | $ | 43 | $ | 3 | $ | 40 | $ | 0 | $ | 43 | |||||||||
Long-term debt (including amounts due within one year) | 2,045 | 0 | 2,204 | 0 | 2,204 | ||||||||||||||
Long-term debt to financing trusts | 258 | 0 | 0 | 254 | 254 | ||||||||||||||
31-Dec-12 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Long-term debt (including amounts due within one year) | $ | 2,178 | $ | 0 | $ | 2,468 | $ | 0 | $ | 2,468 | |||||||||
Long-term debt to financing trusts | 258 | 0 | 0 | 263 | 263 | ||||||||||||||
Assets and liabilities measured and recorded at fair value on recurring basis | ' | ||||||||||||||||||
As of September 30, 2013 | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Assets | |||||||||||||||||||
Cash equivalents | $ | 53 | $ | 0 | $ | 0 | $ | 53 | |||||||||||
Rabbi trust investments | |||||||||||||||||||
Mutual funds(a) | 5 | 0 | 0 | 5 | |||||||||||||||
Rabbi trust investments subtotal | 5 | 0 | 0 | 5 | |||||||||||||||
Total assets | 58 | 0 | 0 | 58 | |||||||||||||||
Liabilities | |||||||||||||||||||
Deferred compensation obligation | 0 | -5 | 0 | -5 | |||||||||||||||
Total liabilities | 0 | -5 | 0 | -5 | |||||||||||||||
Total net assets (liabilities) | $ | 58 | $ | -5 | $ | 0 | $ | 53 | |||||||||||
As of December 31, 2012 | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Assets | |||||||||||||||||||
Cash equivalents | $ | 33 | $ | 0 | $ | 0 | $ | 33 | |||||||||||
Rabbi trust investments | |||||||||||||||||||
Mutual funds | 5 | 0 | 0 | 5 | |||||||||||||||
Rabbi trust investments subtotal | 5 | 0 | 0 | 5 | |||||||||||||||
Total assets | 38 | 0 | 0 | 38 | |||||||||||||||
Liabilities | |||||||||||||||||||
Deferred compensation obligation | 0 | -5 | 0 | -5 | |||||||||||||||
Total liabilities | 0 | -5 | 0 | -5 | |||||||||||||||
Total net assets (liabilities) | $ | 38 | $ | -5 | $ | 0 | $ | 33 |
Derivative_Financial_Instrumen1
Derivative Financial Instruments (Tables) | 9 Months Ended | |||||||||||||||||||||||||||||||||||||
Sep. 30, 2013 | ||||||||||||||||||||||||||||||||||||||
Derivative Financial Instruments [Line Items] | ' | |||||||||||||||||||||||||||||||||||||
Gain or loss on the hedged items and the offsetting loss or gain on the related interest rate swaps in interest expense | ' | |||||||||||||||||||||||||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||||||||||||||||||||||||
30-Sep-13 | 30-Sep-13 | |||||||||||||||||||||||||||||||||||||
Gain (Loss) on Swaps | Gain (Loss) on Borrowings | Gain (Loss) on Swaps | Gain (Loss) on Borrowings | |||||||||||||||||||||||||||||||||||
Generation (a) | Exelon | Generation | Exelon | Generation (a) | Exelon | Generation | Exelon | |||||||||||||||||||||||||||||||
$ | -4 | $ | 4 | $ | -1 | $ | -5 | $ | -13 | $ | 1 | $ | 0 | $ | -2 | |||||||||||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||||||||||||||||||||||||
30-Sep-12 | 30-Sep-12 | |||||||||||||||||||||||||||||||||||||
Gain (Loss) on Swaps | Gain (Loss) on Borrowings | Gain (Loss) on Swaps | Gain (Loss) on Borrowings | |||||||||||||||||||||||||||||||||||
Generation | Exelon | Generation | Exelon | Generation | Exelon | Generation | Exelon | |||||||||||||||||||||||||||||||
$ | -1 | $ | 0 | $ | -3 | $ | 0 | $ | -3 | $ | -2 | $ | -6 | $ | 2 | |||||||||||||||||||||||
__________ | ||||||||||||||||||||||||||||||||||||||
For the three and nine months ended September 30, 2013, the loss on Generation swaps included $4 million and $12 million, respectively, realized in earnings, with an immaterial amount excluded from hedge effectiveness testing. | ||||||||||||||||||||||||||||||||||||||
Summary of the derivative fair value | ' | |||||||||||||||||||||||||||||||||||||
Generation | Other | Exelon | ||||||||||||||||||||||||||||||||||||
Description | Derivatives Designated as Hedging Instruments | Economic Hedges | Proprietary Trading (a) | Collateral and Netting (b) | Subtotal | Derivatives Designated as Hedging Instruments | Total | |||||||||||||||||||||||||||||||
Mark-to-market derivative assets (Current Assets) | $ | - | $ | 3 | $ | 18 | $ | -19 | $ | 2 | $ | - | $ | 2 | ||||||||||||||||||||||||
Mark-to-market derivative assets (Noncurrent Assets) | 27 | 5 | 17 | -16 | 33 | 13 | 46 | |||||||||||||||||||||||||||||||
Total mark-to-market derivative assets | $ | 27 | $ | 8 | $ | 35 | $ | -35 | $ | 35 | $ | 13 | $ | 48 | ||||||||||||||||||||||||
Mark-to-market derivative liabilities (Current Liabilities) | $ | -1 | $ | -1 | $ | -19 | $ | 19 | $ | -2 | $ | - | $ | -2 | ||||||||||||||||||||||||
Mark-to-market derivative liabilities (Noncurrent liabilities) | -14 | - | -16 | 16 | -14 | - | -14 | |||||||||||||||||||||||||||||||
Total mark-to-market derivative liabilities | $ | -15 | $ | -1 | $ | -35 | $ | 35 | $ | -16 | $ | - | $ | -16 | ||||||||||||||||||||||||
Total mark-to-market derivative net assets (liabilities) | $ | 12 | $ | 7 | $ | 0 | $ | 0 | $ | 19 | $ | 13 | $ | 32 | ||||||||||||||||||||||||
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 interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates. | ||||||||||||||||||||||||||||||||||||||
Represents the netting of fair value balances with the same counterparty and any associated cash collateral. | ||||||||||||||||||||||||||||||||||||||
Generation | Other | Exelon | ||||||||||||||||||||||||||||||||||||
Description | Derivatives Designated as Hedging Instruments | Economic Hedges | Proprietary Trading (a) | Collateral and Netting (b) | Subtotal | Derivatives Designated as Hedging Instruments | Total | |||||||||||||||||||||||||||||||
Mark-to-market derivative assets (Current Assets) | $ | - | $ | 3 | $ | 20 | $ | -19 | $ | 4 | $ | - | $ | 4 | ||||||||||||||||||||||||
Mark-to-market derivative assets (Noncurrent Assets) | 38 | 8 | 32 | -32 | 46 | 13 | 59 | |||||||||||||||||||||||||||||||
Total mark-to-market derivative assets | $ | 38 | $ | 11 | $ | 52 | $ | -51 | $ | 50 | $ | 13 | $ | 63 | ||||||||||||||||||||||||
Mark-to-market derivative liabilities (Current Liabilities) | $ | -1 | $ | -1 | $ | -19 | $ | 19 | $ | -2 | $ | - | $ | -2 | ||||||||||||||||||||||||
Mark-to-market derivative liabilities (Noncurrent liabilities) | -31 | - | -32 | 32 | -31 | - | -31 | |||||||||||||||||||||||||||||||
Total mark-to-market derivative liabilities | -32 | -1 | -51 | 51 | -33 | - | -33 | |||||||||||||||||||||||||||||||
Total mark-to-market derivative net assets (liabilities) | $ | 6 | $ | 10 | $ | 1 | $ | - | $ | 17 | $ | 13 | $ | 30 | ||||||||||||||||||||||||
Generation enters into interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The characterization of the interest rate derivative contracts between the proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rate exposure. Generation does not utilize interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates. | ||||||||||||||||||||||||||||||||||||||
Represents the netting of fair value balances with the same counterparty and any associated cash collateral. | ||||||||||||||||||||||||||||||||||||||
Generation | ComEd | Exelon | ||||||||||||||||||||||||||||||||||||
Economic | Proprietary | Collateral and | Economic | Total | ||||||||||||||||||||||||||||||||||
Derivatives | Hedges | Trading | Netting (a) | Subtotal (b) | Hedges (c) | Derivatives | ||||||||||||||||||||||||||||||||
Mark-to-market | ||||||||||||||||||||||||||||||||||||||
derivative assets (current assets) | $ | 2,244 | $ | 1,577 | $ | -3,093 | $ | 728 | $ | 0 | $ | 728 | ||||||||||||||||||||||||||
Mark-to-market | ||||||||||||||||||||||||||||||||||||||
derivative assets (noncurrent assets) | 1,540 | 447 | -1,254 | 733 | 0 | 733 | ||||||||||||||||||||||||||||||||
Total mark-to-market | ||||||||||||||||||||||||||||||||||||||
derivative assets | $ | 3,784 | $ | 2,024 | $ | -4,347 | $ | 1,461 | $ | 0 | $ | 1,461 | ||||||||||||||||||||||||||
Mark-to-market | ||||||||||||||||||||||||||||||||||||||
derivative liabilities (current liabilities) | $ | -1,812 | $ | -1,538 | $ | 3,242 | $ | -108 | $ | -16 | $ | -124 | ||||||||||||||||||||||||||
Mark-to-market | ||||||||||||||||||||||||||||||||||||||
derivative liabilities (noncurrent liabilities) | -911 | -438 | 1,251 | -98 | -106 | -204 | ||||||||||||||||||||||||||||||||
Total mark-to-market | ||||||||||||||||||||||||||||||||||||||
derivative liabilities | $ | -2,723 | $ | -1,976 | $ | 4,493 | $ | -206 | $ | -122 | $ | -328 | ||||||||||||||||||||||||||
Total mark-to-market | ||||||||||||||||||||||||||||||||||||||
derivative net assets (liabilities) | $ | 1,061 | $ | 48 | $ | 146 | $ | 1,255 | $ | -122 | $ | 1,133 | ||||||||||||||||||||||||||
__________ | ||||||||||||||||||||||||||||||||||||||
(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 $86 million and $8 million, respectively, and current and noncurrent liabilities are shown net of collateral of $(235) million and $(5) million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $146 million at September 30, 2013. | ||||||||||||||||||||||||||||||||||||||
(c) Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers. | ||||||||||||||||||||||||||||||||||||||
Generation | ComEd | Exelon | ||||||||||||||||||||||||||||||||||||
Economic | Proprietary | Collateral and | Economic | Intercompany | Total | |||||||||||||||||||||||||||||||||
Derivatives | Hedges (a) | Trading | Netting(b) | Subtotal (c) | Hedges (a) (d) | Eliminations (a) | Derivatives | |||||||||||||||||||||||||||||||
Mark-to-market | ||||||||||||||||||||||||||||||||||||||
derivative assets (current assets) | $ | 2,883 | $ | 2,469 | $ | -4,418 | $ | 934 | $ | 0 | $ | 0 | $ | 934 | ||||||||||||||||||||||||
Mark-to-market | ||||||||||||||||||||||||||||||||||||||
derivative assets with affiliate (current assets) | 226 | 0 | 0 | 226 | 0 | -226 | 0 | |||||||||||||||||||||||||||||||
Mark-to-market | ||||||||||||||||||||||||||||||||||||||
derivative assets (noncurrent assets) | 1,792 | 724 | -1,638 | 878 | 0 | 0 | 878 | |||||||||||||||||||||||||||||||
Mark-to-market | ||||||||||||||||||||||||||||||||||||||
Total mark-to-market | ||||||||||||||||||||||||||||||||||||||
derivative assets | $ | 4,901 | $ | 3,193 | $ | -6,056 | $ | 2,038 | $ | 0 | $ | -226 | $ | 1,812 | ||||||||||||||||||||||||
Mark-to-market | ||||||||||||||||||||||||||||||||||||||
derivative liabilities (current liabilities) | $ | -2,419 | $ | -2,432 | $ | 4,519 | $ | -332 | $ | -18 | $ | 0 | $ | -350 | ||||||||||||||||||||||||
Mark-to-market | ||||||||||||||||||||||||||||||||||||||
derivative liability with affiliate (current liabilities) | 0 | 0 | 0 | 0 | -226 | 226 | 0 | |||||||||||||||||||||||||||||||
Mark-to-market | ||||||||||||||||||||||||||||||||||||||
derivative liabilities (noncurrent liabilities) | -1,080 | -689 | 1,568 | -201 | -49 | 0 | -250 | |||||||||||||||||||||||||||||||
Mark-to-market | ||||||||||||||||||||||||||||||||||||||
Total mark-to-market | ||||||||||||||||||||||||||||||||||||||
derivative liabilities | $ | -3,499 | $ | -3,121 | $ | 6,087 | $ | -533 | $ | -293 | $ | 226 | $ | -600 | ||||||||||||||||||||||||
Total mark-to-market | ||||||||||||||||||||||||||||||||||||||
derivative net assets (liabilities) | $ | 1,402 | $ | 72 | $ | 31 | $ | 1,505 | $ | -293 | $ | 0 | $ | 1,212 | ||||||||||||||||||||||||
__________ | ||||||||||||||||||||||||||||||||||||||
(a) Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $226 million related to the fair value of the five-year financial swap contract between Generation and ComEd, as described above. For Generation excludes $28 million of noncurrent liability relating to an interest rate swap in connection with a loan agreement to fund Antelope Valley as discussed above. | ||||||||||||||||||||||||||||||||||||||
(b) Exelon and Generation net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, and letters of credit. These are not reflected in the table above. | ||||||||||||||||||||||||||||||||||||||
(c) Current and noncurrent assets are shown net of collateral of $113 million and $201 million, respectively, and current and noncurrent liabilities are shown net of collateral of $ (214) million and $ (131) million, respectively. The total cash collateral received, net of cash collateral posted and offset against mark-to-market assets and liabilities was $31 million at December 31, 2012. | ||||||||||||||||||||||||||||||||||||||
(d) Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers. | ||||||||||||||||||||||||||||||||||||||
The activity of accumulated OCI related to cash flow hedges | ' | |||||||||||||||||||||||||||||||||||||
Total Cash Flow Hedge OCI Activity, Net of Income Tax | ||||||||||||||||||||||||||||||||||||||
Generation | Exelon | |||||||||||||||||||||||||||||||||||||
Three Months Ended September 30, 2013 | Income Statement Location | Energy-Related Hedges | Total Cash Flow Hedges | |||||||||||||||||||||||||||||||||||
Accumulated OCI derivative gain at June 30, 2013 | $ | 255 | (a) | $ | 245 | |||||||||||||||||||||||||||||||||
Effective portion of changes in fair value | 0 | 2 | (b) | |||||||||||||||||||||||||||||||||||
Reclassifications from accumulated OCI to net income | Operating Revenues | -51 | -48 | |||||||||||||||||||||||||||||||||||
Accumulated OCI derivative gain at September 30, 2013 | $ | 204 | (a) | $ | 199 | |||||||||||||||||||||||||||||||||
(a) Excludes $11 million of losses, net of taxes, related to interest rate swaps and treasury rate locks as of September 30, 2013 and June 30, 2013. | ||||||||||||||||||||||||||||||||||||||
(b) Includes $2 million of gains, net of taxes, related to the effective portion of changes in fair value of interest rate swaps and treasury rate locks. | ||||||||||||||||||||||||||||||||||||||
Total Cash Flow Hedge OCI Activity, Net of Income Tax | ||||||||||||||||||||||||||||||||||||||
Generation | Exelon | |||||||||||||||||||||||||||||||||||||
Nine Months Ended September 30, 2013 | Income Statement Location | Energy-Related Hedges | Total Cash Flow Hedges | |||||||||||||||||||||||||||||||||||
Accumulated OCI derivative gain at December 31, 2012 | $ | 532 | (a)(c) | $ | 368 | |||||||||||||||||||||||||||||||||
Effective portion of changes in fair value | 0 | 25 | (d) | |||||||||||||||||||||||||||||||||||
Reclassifications from accumulated OCI to net income | Operating Revenues | -328 | (b) | -194 | ||||||||||||||||||||||||||||||||||
Accumulated OCI derivative gain at September 30, 2013 | $ | 204 | (c) | $ | 199 | |||||||||||||||||||||||||||||||||
__________ | ||||||||||||||||||||||||||||||||||||||
(a) Includes $133 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, as of December 31, 2012. | ||||||||||||||||||||||||||||||||||||||
(b) Includes $133 million of losses, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd. | ||||||||||||||||||||||||||||||||||||||
(c) Excludes $11 million of losses and $20 million of losses, net of taxes, related to interest rate swaps and treasury locks as of September 30, 2013 and December 31, 2012, respectively. | ||||||||||||||||||||||||||||||||||||||
(d) Includes $25 million of losses, net of taxes, related to the effective portion of changes in fair value of interest rate swaps and treasury rate locks. | ||||||||||||||||||||||||||||||||||||||
Total Cash Flow Hedge OCI Activity, Net of Income Tax | ||||||||||||||||||||||||||||||||||||||
Generation | Exelon | |||||||||||||||||||||||||||||||||||||
Three Months Ended September 30, 2012 | Income Statement Location | Energy-Related Hedges | Total Cash Flow Hedges | |||||||||||||||||||||||||||||||||||
Accumulated OCI derivative gain at June 30, 2012 | $ | 923 | (a)(c) | $ | 547 | |||||||||||||||||||||||||||||||||
Effective portion of changes in fair value | - | (e) | - | (d) | ||||||||||||||||||||||||||||||||||
Reclassifications from accumulated OCI to net income | Operating Revenues | -171 | (b) | -88 | ||||||||||||||||||||||||||||||||||
Accumulated OCI derivative gain at September 30, 2012 | $ | 752 | (a)(c) | $ | 459 | |||||||||||||||||||||||||||||||||
. | ||||||||||||||||||||||||||||||||||||||
(a) Includes $232 million and $315 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd as of September 30, 2012 and June 30, 2012, respectively. | ||||||||||||||||||||||||||||||||||||||
(b) Includes a $83 million of losses, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd. | ||||||||||||||||||||||||||||||||||||||
(c) Excludes $22 million of losses and $22 million of gains, net of taxes, related to interest rate swaps and treasury rate locks for the three months ended September 30, 2012 and June 30, 2012 respectively. | ||||||||||||||||||||||||||||||||||||||
(d) Includes $0 million of losses, net of taxes, at Generation related to the effective portion of changes in fair value of interest rate swaps and treasury rate locks. | ||||||||||||||||||||||||||||||||||||||
(e) Due to de-designation of all commodity cash flow positions prior to the merger date, there are no changes in fair value. | ||||||||||||||||||||||||||||||||||||||
Total Cash Flow Hedge OCI Activity, Net of Income Tax | ||||||||||||||||||||||||||||||||||||||
Generation | Exelon | |||||||||||||||||||||||||||||||||||||
Nine Months Ended September 30, 2012 | Income Statement Location | Energy-Related Hedges | Total Cash Flow Hedges | |||||||||||||||||||||||||||||||||||
Accumulated OCI derivative gain at December 31, 2011 | $ | 925 | (a)(c) | $ | 488 | |||||||||||||||||||||||||||||||||
Effective portion of changes in fair value | 432 | (e) | 301 | (d) | ||||||||||||||||||||||||||||||||||
Reclassifications from accumulated OCI to net income | Operating Revenues | -608 | (b) | -333 | ||||||||||||||||||||||||||||||||||
Ineffective portion recognized in income | Operating Revenues | 3 | 3 | |||||||||||||||||||||||||||||||||||
Accumulated OCI derivative gain at September 30, 2012 | $ | 752 | (a)(c) | $ | 459 | |||||||||||||||||||||||||||||||||
_____________ | ||||||||||||||||||||||||||||||||||||||
(a) Includes $232 million and $420 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, as of September 30, 2012 and December 31, 2011. | ||||||||||||||||||||||||||||||||||||||
(b) Includes $276 million of losses, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd. | ||||||||||||||||||||||||||||||||||||||
(c) Excludes $22 million of losses and $10 million of losses, net of taxes, related to interest rate swaps and treasury rate locks for the nine months ended September 30, 2012 and year ended December 31, 2011, respectively. | ||||||||||||||||||||||||||||||||||||||
(d) Includes $12 million of losses, net of taxes, related to the effective portion of changes in fair value of interest rate swaps and treasury rate locks. | ||||||||||||||||||||||||||||||||||||||
(e) Includes $88 million of gains, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd through the date of de-designation prior to the merger. | ||||||||||||||||||||||||||||||||||||||
Other Derivatives - Gain (loss) and reclassification | ' | |||||||||||||||||||||||||||||||||||||
Prior to the merger, the five-year financial swap contract between Generation and ComEd was de-designated. As a result, all prospective changes in fair value are recorded to operating revenues and eliminated in consolidation. | ||||||||||||||||||||||||||||||||||||||
Change in fair value and reclassification of derivative contracts | ' | |||||||||||||||||||||||||||||||||||||
Generation | Intercompany Eliminations | Exelon | ||||||||||||||||||||||||||||||||||||
Purchased | ||||||||||||||||||||||||||||||||||||||
Operating | Power | Operating | ||||||||||||||||||||||||||||||||||||
Three Months Ended September 30, 2013 | Revenues | and Fuel | Total | Revenues (a) | Total | |||||||||||||||||||||||||||||||||
Change in fair value | $ | 175 | $ | 5 | $ | 180 | $ | 0 | $ | 180 | ||||||||||||||||||||||||||||
Reclassification to realized at settlement | 41 | 25 | 66 | 0 | 66 | |||||||||||||||||||||||||||||||||
Net mark-to-market gains | $ | 216 | $ | 30 | $ | 246 | $ | 0 | $ | 246 | ||||||||||||||||||||||||||||
Generation | Intercompany Eliminations | Exelon | ||||||||||||||||||||||||||||||||||||
Purchased | ||||||||||||||||||||||||||||||||||||||
Operating | Power | Operating | ||||||||||||||||||||||||||||||||||||
Nine Months Ended September 30, 2013 | Revenues | and Fuel | Total | Revenues (a) | Total | |||||||||||||||||||||||||||||||||
Change in fair value | $ | 149 | $ | 74 | $ | 223 | $ | -6 | $ | 217 | ||||||||||||||||||||||||||||
Reclassification to realized at settlement | -15 | 63 | 48 | 13 | 61 | |||||||||||||||||||||||||||||||||
Net mark-to-market gains | $ | 134 | $ | 137 | $ | 271 | $ | 7 | $ | 278 | ||||||||||||||||||||||||||||
Generation | Intercompany Eliminations | Exelon | ||||||||||||||||||||||||||||||||||||
Purchased | ||||||||||||||||||||||||||||||||||||||
Operating | Power | Operating | ||||||||||||||||||||||||||||||||||||
Three Months Ended September 30, 2012 | Revenues | and Fuel | Total | Revenues (a) | Total | |||||||||||||||||||||||||||||||||
Change in fair value | $ | -255 | $ | 129 | $ | -126 | $ | 35 | $ | -91 | ||||||||||||||||||||||||||||
Reclassification to realized at settlement | 20 | 122 | 142 | -19 | 123 | |||||||||||||||||||||||||||||||||
Net mark-to-market gains (losses) | $ | -235 | $ | 251 | $ | 16 | $ | 16 | $ | 32 | ||||||||||||||||||||||||||||
Generation | Intercompany Eliminations | Exelon | ||||||||||||||||||||||||||||||||||||
Purchased | ||||||||||||||||||||||||||||||||||||||
Operating | Power | Operating | ||||||||||||||||||||||||||||||||||||
Nine Months Ended September 30, 2012 | Revenues | and Fuel | Total | Revenues (a) | Total | |||||||||||||||||||||||||||||||||
Change in fair value | $ | -85 | $ | 121 | $ | 36 | $ | 62 | $ | 98 | ||||||||||||||||||||||||||||
Reclassification to realized at settlement | -81 | 326 | 245 | -29 | 216 | |||||||||||||||||||||||||||||||||
Net mark-to-market gains (losses) | $ | -166 | $ | 447 | $ | 281 | $ | 33 | $ | 314 | ||||||||||||||||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||||||||||||||||||||||||
Location on Income | September 30, | September 30, | ||||||||||||||||||||||||||||||||||||
Statement | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||||||||||||||||||||
Change in fair value | Operating Revenue | $ | 0 | $ | -2 | $ | 1 | $ | 12 | |||||||||||||||||||||||||||||
Reclassification to realized at | ||||||||||||||||||||||||||||||||||||||
settlement | Operating Revenue | -40 | 25 | -36 | 57 | |||||||||||||||||||||||||||||||||
Net mark-to-market gains (losses) | Operating Revenue | $ | -40 | $ | 23 | $ | -35 | $ | 69 | |||||||||||||||||||||||||||||
Information on Generation's credit exposure for all derivative instruments, normal purchase normal sales, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements | ' | |||||||||||||||||||||||||||||||||||||
Total | Number of | Net Exposure of | ||||||||||||||||||||||||||||||||||||
Exposure | Counterparties | Counterparties | ||||||||||||||||||||||||||||||||||||
Before Credit | Credit | Net | Greater than 10% | Greater than 10% | ||||||||||||||||||||||||||||||||||
Rating as of September 30, 2013 | Collateral | Collateral | Exposure | of Net Exposure | of Net Exposure | |||||||||||||||||||||||||||||||||
Investment grade | $ | 1,767 | $ | 191 | $ | 1,576 | 1 | $ | 478 | |||||||||||||||||||||||||||||
Non-investment grade | 16 | 9 | 7 | 0 | 0 | |||||||||||||||||||||||||||||||||
No external ratings | ||||||||||||||||||||||||||||||||||||||
Internally rated - investment grade | 472 | 6 | 466 | 1 | 238 | |||||||||||||||||||||||||||||||||
Internally rated - non-investment | ||||||||||||||||||||||||||||||||||||||
grade | 18 | 1 | 17 | 0 | 0 | |||||||||||||||||||||||||||||||||
Total | $ | 2,273 | $ | 207 | $ | 2,066 | 2 | $ | 716 | |||||||||||||||||||||||||||||
Net Credit Exposure by Type of Counterparty | As of September 30, 2013 | |||||||||||||||||||||||||||||||||||||
Investor-owned utilities, marketers and power producers | $ | 743 | ||||||||||||||||||||||||||||||||||||
Energy cooperatives and municipalities | 916 | |||||||||||||||||||||||||||||||||||||
Financial institutions | 355 | |||||||||||||||||||||||||||||||||||||
Other | 52 | |||||||||||||||||||||||||||||||||||||
Total | $ | 2,066 | ||||||||||||||||||||||||||||||||||||
Credit-Risk Related Contingent Feature | 30-Sep-13 | |||||||||||||||||||||||||||||||||||||
Gross Fair Value of Derivative Contracts Containing this Feature (a) | Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements (b) | Net Fair Value of Derivative Contracts Containing This Feature (c) | ||||||||||||||||||||||||||||||||||||
($961) | $790 | ($171) | ||||||||||||||||||||||||||||||||||||
Credit-Risk Related Contingent Feature | 31-Dec-12 | |||||||||||||||||||||||||||||||||||||
Gross Fair Value of Derivative Contracts Containing this Feature (a) | Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements (b) | Net Fair Value of Derivative Contracts Containing This Feature (c) | ||||||||||||||||||||||||||||||||||||
($1,849) | $1,426 | ($423) | ||||||||||||||||||||||||||||||||||||
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. | ||||||||||||||||||||||||||||||||||||||
Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which a Registrant could potentially be required to post collateral. | ||||||||||||||||||||||||||||||||||||||
Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based. | ||||||||||||||||||||||||||||||||||||||
Debt_and_Credit_Agreements_Yea
Debt and Credit Agreements Year-End (Tables) | 9 Months Ended | ||||||||
Sep. 30, 2013 | |||||||||
Debt Tables [Line Items] | ' | ||||||||
Schedule Of Short Term Debt [Text Block] | ' | ||||||||
Type of Credit Facility | Amount (a) | Expiration Dates | Capacity Type | ||||||
Exelon Corporate | (In billions) | ||||||||
Syndicated Revolver | $ | 0.5 | Aug-18 | Letters of credit and cash | |||||
Generation | |||||||||
Syndicated Revolver | 5.3 | Aug-18 | Letters of credit and cash | ||||||
Bilateral | 0.3 | December 2015 and March 2016 | Letters of credit and cash | ||||||
Bilateral | 0.1 | Jan-15 | Letters of credit | ||||||
ComEd | |||||||||
Syndicated Revolver | 1 | Mar-18 | Letters of credit and cash | ||||||
PECO | |||||||||
Syndicated Revolver | 0.6 | Aug-18 | Letters of credit and cash | ||||||
BGE | |||||||||
Syndicated Revolver | 0.6 | Aug-18 | Letters of credit and cash | ||||||
Total | $ | 8.4 | |||||||
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 expire on October 18, 2014 and are solely utilized to issue letters of credit. As of September 30, 2013, letters of credit issued under these agreements for Generation, ComEd, PECO and BGE totaled $24 million, $26 million, $21 million and $1 million, respectively. | |||||||||
Schedule Of Short Term Borrowing Activity [Text Block] | ' | ||||||||
Commercial Paper Borrowings | 30-Sep-13 | 31-Dec-12 | |||||||
Exelon Corporate | $ | 0 | $ | 0 | |||||
Generation | 0 | 0 | |||||||
ComEd | 153 | 0 | |||||||
PECO | 0 | 0 | |||||||
BGE | 40 | 0 | |||||||
Schedule Of Maturities Of Long Term Debt [Text Block] | ' | ||||||||
_______________ | |||||||||
Represents debt obligations assumed by Exelon as part of the merger on March 12, 2012 that became callable at face value on June 15, 2013. 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 as of December 31, 2012 included in long-term debt to affiliate on Generation's Consolidated Balance Sheets and notes receivable from affiliates at Exelon Corporate, which are eliminated in consolidation on Exelon's Consolidated Balance Sheets. The third-party debt obligations were reported in Long-term Debt on Exelon's Consolidated Balance Sheets as of December 31, 2012. The debentures were redeemed and the intercompany loan agreements repaid on June 15, 2013. | |||||||||
Debt_and_Credit_Agreements_Qua
Debt and Credit Agreements Quarter-End (Tables) | 9 Months Ended | ||||||||||
Sep. 30, 2013 | |||||||||||
Debt and Credit Agreements [Line Items] | ' | ||||||||||
Commercial paper and credit facility borrowings outstanding | ' | ||||||||||
Type of Credit Facility | Amount (a) | Expiration Dates | Capacity Type | ||||||||
Exelon Corporate | (In billions) | ||||||||||
Syndicated Revolver | $ | 0.5 | Aug-18 | Letters of credit and cash | |||||||
Generation | |||||||||||
Syndicated Revolver | 5.3 | Aug-18 | Letters of credit and cash | ||||||||
Bilateral | 0.3 | December 2015 and March 2016 | Letters of credit and cash | ||||||||
Bilateral | 0.1 | Jan-15 | Letters of credit | ||||||||
ComEd | |||||||||||
Syndicated Revolver | 1 | Mar-18 | Letters of credit and cash | ||||||||
PECO | |||||||||||
Syndicated Revolver | 0.6 | Aug-18 | Letters of credit and cash | ||||||||
BGE | |||||||||||
Syndicated Revolver | 0.6 | Aug-18 | Letters of credit and cash | ||||||||
Total | $ | 8.4 | |||||||||
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 expire on October 18, 2014 and are solely utilized to issue letters of credit. As of September 30, 2013, letters of credit issued under these agreements for Generation, ComEd, PECO and BGE totaled $24 million, $26 million, $21 million and $1 million, respectively. | |||||||||||
Issuance of Long-Term Debt | ' | ||||||||||
Company | Type | Interest Rate | Maturity | Amount | Use of Proceeds | ||||||
Generation | Upstream Gas Lending Agreement | 2.210 - 2.440 | % | 22-Jul-16 | $ | 5 | Used to fund Upstream gas activities | ||||
Generation | DOE Project Financing | 2.535 - 3.353 | % | 5-Jan-37 | $ | 204 | Funding for Antelope Valley Solar Development | ||||
Generation | Energy Efficiency Project Financing | 4.4 | % | 31-Aug-14 | $ | 9 | Funding to install energy conservation measures in Beckley, West Virginia | ||||
Generation | Continental Wind Senior Secured Notes | 6 | % | 28-Feb-33 | $ | 613 | Used for general corporate purposes | ||||
ComEd | First Mortgage Bonds | 4.6 | % | 15-Aug-43 | $ | 350 | Used to repay outstanding commercial paper obligations and for general corporate purposes | ||||
PECO | First and Refunding Mortgage Bonds | 1.2 | % | 15-Oct-16 | $ | 300 | Used to pay at maturity first and refunding mortgage bonds due October 15, 2013 and other general corporate purposes | ||||
PECO | First and Refunding Mortgage Bonds | 4.8 | % | 15-Oct-43 | $ | 250 | Used to pay at maturity first and refunding mortgage bonds due October 15, 2013 and other general corporate purposes | ||||
BGE | Senior Notes | 3.35 | % | 1-Jul-23 | $ | 300 | Used to partially refinance Notes due July 1, 2013 and for general corporate purposes | ||||
Company | Type | Interest Rate | Maturity | Amount | Use of Proceeds | ||||||
Generation | Senior Notes | 4.25 | % | 15-Jun-22 | $ | 523 | Used for general corporate purposes and issued in connection with the Exchange Offer | ||||
Generation | Senior Notes | 5.6 | % | 15-Jun-42 | $ | 788 | Used for general corporate purposes and issued in connection with the Exchange Offer | ||||
Generation | CEU Credit Agreement | 1.99 | % | 16-Jun-16 | $ | 43 | Used to fund upstream gas activities | ||||
Generation | DOE Project Financing | 2.330 - 3.092 | % | 5-Jan-37 | $ | 100 | Funding for Antelope Valley Solar Development | ||||
Generation | Clean Horizons | 2.5 | % | 7-Jun-30 | $ | 38 | Funding for Maryland solar development | ||||
PECO | First and Refunding Mortgage Bonds | 2.375 | % | 15-Sep-22 | $ | 350 | Used to pay at maturity First Mortgage Bonds due October 1, 2012 and for general corporate purposes | ||||
BGE | Notes | 2.8 | % | 15-Aug-32 | $ | 250 | Used to repay total outstanding commercial paper and for general corporate purposes | ||||
Retirement of Long-Term Debt | ' | ||||||||||
Company | Type | Interest Rate | Maturity | Amount | |||||||
Generation | Kennett Square Capital Lease | 7.83 | % | 20-Sep-20 | $ | 2 | |||||
Generation | Solar Revolver | 1.930 - 1.950 | % | 7-Jul-14 | $ | 18 | |||||
Generation | Clean Horizons | 2.563 | % | 7-Sep-30 | $ | 1 | |||||
Generation (a) | Series A Junior Subordinated Debentures | 8.625 | % | 15-Jun-63 | $ | 450 | |||||
ComEd | First Mortgage Bonds Series 92 | 7.625 | % | 15-Apr-13 | $ | 125 | |||||
ComEd | First Mortgage Bonds Series 94 | 7.5 | % | 1-Jul-13 | $ | 127 | |||||
BGE | Senior Notes | 6.125 | % | 1-Jul-13 | $ | 400 | |||||
BGE | Rate Stabilization Bonds | 5.72 | % | 1-Apr-17 | $ | 33 | |||||
Company | Type | Interest Rate | Maturity | Amount | |||||||
ComEd | First Mortgage Bond Series 98 | 6.15 | % | 15-Mar-12 | $ | 450 | |||||
BGE | Rate Stabilization Bonds | 5.68 | % | 1-Apr-17 | $ | 31 | |||||
BGE | Medium Term Notes | 6.73 - 6.75 | % | 15-Jun-12 | $ | 110 | |||||
Generation | Kennett Square Capital Lease | 7.83 | % | 20-Sep-20 | $ | 2 | |||||
Generation | Armstrong Co. tax-exempt | 5 | % | 1-Dec-42 | $ | 46 | |||||
Generation | MEDCO Tax-Exempt Bonds | Various | 1-Apr-24 | $ | 75 | ||||||
Generation | Solar Revolver | 2.49 | % | 7-Jul-14 | $ | 13 | |||||
Generation | CEU Credit Agreement | 2.27 | % | 16-Jul-16 | $ | 3 | |||||
Exelon | Senior Notes | 7.6 | % | 1-Apr-32 | $ | 442 | |||||
Exelon | Medium Term Notes | 7.3 | % | 1-Jun-12 | $ | 2 |
Income_Taxes_Tables
Income Taxes (Tables) | 9 Months Ended | |||||||||||||||
Sep. 30, 2013 | ||||||||||||||||
Income Taxes [Line Items] | ' | |||||||||||||||
Effective Income Tax Rate Reconciliation | ' | |||||||||||||||
For the Three Months Ended September 30, 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 | 3 | 2.6 | 5.4 | -0.3 | 5.6 | |||||||||||
Qualified nuclear decommissioning trust fund income | 3.5 | 5.3 | 0 | 0 | 0 | |||||||||||
Tax exempt income | -0.2 | -0.3 | 0 | 0 | 0 | |||||||||||
Health care reform legislation | 0.1 | 0 | 0.4 | 0 | 0.2 | |||||||||||
Amortization of investment tax credit, net deferred taxes | -1.5 | -2.1 | -0.4 | -0.1 | -0.3 | |||||||||||
Plant basis differences | -0.8 | 0 | -0.4 | -6.9 | 0.1 | |||||||||||
Production tax credits and other credits | -2.2 | -3.3 | 0 | 0 | 0 | |||||||||||
Other | 0.5 | 0.1 | 0.3 | -0.1 | -0.2 | |||||||||||
Effective income tax rate | 37.4 | % | 37.3 | % | 40.3 | % | 27.6 | % | 40.4 | % | ||||||
For the Nine Months Ended September 30, 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 | 5.3 | 1.8 | 5.2 | 1.9 | 5.6 | |||||||||||
Qualified nuclear decommissioning trust fund income | 3.2 | 5.1 | 0 | 0 | 0 | |||||||||||
Tax exempt income | -0.2 | -0.3 | 0 | 0 | 0 | |||||||||||
Health care reform legislation | 0.1 | 0 | 0.9 | 0 | 0.2 | |||||||||||
Amortization of investment tax credit, net deferred taxes | -2.3 | -3.4 | -0.8 | -0.1 | -0.3 | |||||||||||
Plant basis differences | -1.7 | 0 | -1.2 | -7.3 | -0.4 | |||||||||||
Production tax credits and other credits | -2.4 | -3.9 | 0 | 0 | 0 | |||||||||||
Other | 0.2 | 1.1 | 0.8 | 0 | 0 | |||||||||||
Effective income tax rate | 37.2 | % | 35.4 | % | 39.9 | % | 29.5 | % | 40.1 | % | ||||||
For the Three Months Ended September 30, 2012 | Exelon(a) | Generation(a) | ComEd | PECO | BGE (b) | |||||||||||
U.S. Federal statutory rate | 35 | % | 35 | % | 35 | % | 35 | % | 0 | % | ||||||
Increase (decrease) due to: | ||||||||||||||||
State income taxes, net of Federal income tax benefit | 5.6 | 5.9 | 5 | 3 | 0 | |||||||||||
Qualified nuclear decommissioning trust fund income | 7.8 | 21.5 | 0 | 0 | 0 | |||||||||||
Domestic production activities deduction | 0.3 | 0.8 | 0 | 0 | 0 | |||||||||||
Tax exempt income | -0.2 | -0.5 | 0 | 0 | 0 | |||||||||||
Health care reform legislation | 0 | 0 | 0.6 | 0 | 0 | |||||||||||
Amortization of investment tax credit, net deferred taxes | -4.8 | -13 | -0.5 | -0.3 | 0 | |||||||||||
Plant basis differences | -4.7 | 0 | -0.5 | -21 | 0 | |||||||||||
Production tax credits and other credits | -2.5 | -7.4 | 0 | 0 | 0 | |||||||||||
Fines and Penalties | -0.1 | 0 | 0 | 0 | 0 | |||||||||||
Other (d) | -1.2 | 7.1 | 0 | 0.2 | 0 | |||||||||||
Effective income tax rate | 35.2 | % | 49.4 | % | 39.6 | % | 16.9 | % | 0 | % | ||||||
For the Nine Months Ended September 30, 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 | -4.7 | 2.5 | 5.4 | 3.2 | 2.3 | |||||||||||
Qualified nuclear decommissioning trust fund income | 6.9 | 10.9 | 0 | 0 | 0 | |||||||||||
Tax exempt income | -0.3 | -0.5 | 0 | 0 | 0 | |||||||||||
Health care reform legislation | 0.2 | 0 | 0.6 | 0 | -4.6 | |||||||||||
Amortization of investment tax credit, net deferred taxes | -2.3 | -3.3 | -0.5 | -0.3 | 2.9 | |||||||||||
Plant basis differences | -2.2 | 0 | -0.2 | -9.7 | 7.2 | |||||||||||
Production tax credits and other credits | -2.6 | -4.3 | 0 | 0 | 0 | |||||||||||
Fines and Penalties | 3.8 | 6 | 0 | 0 | 0 | |||||||||||
Merger expenses (c) | 3.6 | 0 | 0 | 0 | -14 | |||||||||||
Other | -1.3 | 0.8 | 0.2 | 0 | 4.5 | |||||||||||
Effective income tax rate | 36.1 | % | 47.1 | % | 40.5 | % | 28.2 | % | 33.3 | % | ||||||
(a) Exelon activity for the three and nine months ended September 30, 2012 includes the results of Constellation and BGE for March 12, 2012 - September 30, 2012. Generation activity for the three and nine months ended September 30, 2012 includes the results of Constellation for March 12, 2012 - September 30, 2012. | ||||||||||||||||
(b) BGE activity represents the activity for the three and nine months ended September 30, 2012. BGE activity for the three months ended September 30, 2012 resulted in zero pre-tax income and zero income taxes. BGE recognized a loss before income taxes for the nine months ended September 30, 2012. As a result, positive percentages represent an income tax benefit for BGE for the nine months ended September 30, 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. | ||||||||||||||||
(d) For the three months ended September 30, 2012, Generation's effective tax rate was affected by the resolution of uncertain Federal tax positions (5.3%), the finalization of prior year tax return calculations 4.2%, changes in the forecasted activity attributable to noncontrolling interests 4.1%, and other 4.1%. | ||||||||||||||||
Asset_Retirement_Obligations_T
Asset Retirement Obligations (Tables) | 9 Months Ended | ||||||||||||
Sep. 30, 2013 | |||||||||||||
Asset Retirement Obligations Tables [Line Items] | ' | ||||||||||||
Nuclear decommissioning asset retirement obligation rollforward | ' | ||||||||||||
Nuclear decommissioning ARO at December 31, 2012 (a) | $ | 4,741 | |||||||||||
Accretion expense | 194 | ||||||||||||
Net decrease due to changes in, and timing of, estimated cash flows | -141 | ||||||||||||
Costs incurred to decommission retired plants | -2 | ||||||||||||
Nuclear decommissioning ARO at September 30, 2013 (a) | $ | 4,792 | |||||||||||
Unrealized Gains (Losses) on nuclear decommissioning trust funds | ' | ||||||||||||
Exelon and Generation | |||||||||||||
Three Months Ended | Nine Months Ended | ||||||||||||
September 30, | September 30, | ||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||
Net unrealized gains on decommissioning trust funds — | |||||||||||||
Regulatory Agreement Units (a) | $ | 103 | $ | 202 | $ | 196 | $ | 352 | |||||
Net unrealized gains on decommissioning trust funds — | |||||||||||||
Non-Regulatory Agreement Units (b)(c) | 46 | 71 | 70 | 101 | |||||||||
Zion Station pledged assets | ' | ||||||||||||
Exelon and Generation | |||||||||||||
September 30, | December 31, | ||||||||||||
2013 | 2012 | ||||||||||||
Carrying value of Zion Station pledged assets | $ | 486 | $ | 614 | |||||||||
Payable to Zion Solutions (a) | 443 | 564 | |||||||||||
Current portion of payable to Zion Solutions (b) | 104 | 132 | |||||||||||
Withdrawals by Zion Solutions to pay decommissioning costs (c) | 458 | 335 | |||||||||||
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. | |||||||||||||
Included in Other current liabilities within Exelon's and Generation's Consolidated Balance Sheets. | |||||||||||||
Cumulative withdrawals since September 1, 2010. | |||||||||||||
Exelon Generation Co L L C [Member] | ' | ||||||||||||
Asset Retirement Obligations Tables [Line Items] | ' | ||||||||||||
Nuclear decommissioning asset retirement obligation rollforward | ' | ||||||||||||
Nuclear decommissioning ARO at December 31, 2012 (a) | $ | 4,741 | |||||||||||
Accretion expense | 194 | ||||||||||||
Net decrease due to changes in, and timing of, estimated cash flows | -141 | ||||||||||||
Costs incurred to decommission retired plants | -2 | ||||||||||||
Nuclear decommissioning ARO at September 30, 2013 (a) | $ | 4,792 | |||||||||||
Unrealized Gains (Losses) on nuclear decommissioning trust funds | ' | ||||||||||||
Exelon and Generation | |||||||||||||
Three Months Ended | Nine Months Ended | ||||||||||||
September 30, | September 30, | ||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||
Net unrealized gains on decommissioning trust funds — | |||||||||||||
Regulatory Agreement Units (a) | $ | 103 | $ | 202 | $ | 196 | $ | 352 | |||||
Net unrealized gains on decommissioning trust funds — | |||||||||||||
Non-Regulatory Agreement Units (b)(c) | 46 | 71 | 70 | 101 | |||||||||
Zion Station pledged assets | ' | ||||||||||||
Exelon and Generation | |||||||||||||
September 30, | December 31, | ||||||||||||
2013 | 2012 | ||||||||||||
Carrying value of Zion Station pledged assets | $ | 486 | $ | 614 | |||||||||
Payable to Zion Solutions (a) | 443 | 564 | |||||||||||
Current portion of payable to Zion Solutions (b) | 104 | 132 | |||||||||||
Withdrawals by Zion Solutions to pay decommissioning costs (c) | 458 | 335 | |||||||||||
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. | |||||||||||||
Included in Other current liabilities within Exelon's and Generation's Consolidated Balance Sheets. | |||||||||||||
Cumulative withdrawals since September 1, 2010. | |||||||||||||
Nuclear_Decommissioning_Tables
Nuclear Decommissioning (Tables) | 9 Months Ended | ||||||||||||
Sep. 30, 2013 | |||||||||||||
Schedule Of Nuclear Decommissioning [Line Items] | ' | ||||||||||||
Nuclear decommissioning asset retirement obligation rollforward | ' | ||||||||||||
Nuclear decommissioning ARO at December 31, 2012 (a) | $ | 4,741 | |||||||||||
Accretion expense | 194 | ||||||||||||
Net decrease due to changes in, and timing of, estimated cash flows | -141 | ||||||||||||
Costs incurred to decommission retired plants | -2 | ||||||||||||
Nuclear decommissioning ARO at September 30, 2013 (a) | $ | 4,792 | |||||||||||
Unrealized Gains (Losses) on nuclear decommissioning trust funds | ' | ||||||||||||
Exelon and Generation | |||||||||||||
Three Months Ended | Nine Months Ended | ||||||||||||
September 30, | September 30, | ||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||
Net unrealized gains on decommissioning trust funds — | |||||||||||||
Regulatory Agreement Units (a) | $ | 103 | $ | 202 | $ | 196 | $ | 352 | |||||
Net unrealized gains on decommissioning trust funds — | |||||||||||||
Non-Regulatory Agreement Units (b)(c) | 46 | 71 | 70 | 101 | |||||||||
Zion Station pledged assets | ' | ||||||||||||
Exelon and Generation | |||||||||||||
September 30, | December 31, | ||||||||||||
2013 | 2012 | ||||||||||||
Carrying value of Zion Station pledged assets | $ | 486 | $ | 614 | |||||||||
Payable to Zion Solutions (a) | 443 | 564 | |||||||||||
Current portion of payable to Zion Solutions (b) | 104 | 132 | |||||||||||
Withdrawals by Zion Solutions to pay decommissioning costs (c) | 458 | 335 | |||||||||||
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. | |||||||||||||
Included in Other current liabilities within Exelon's and Generation's Consolidated Balance Sheets. | |||||||||||||
Cumulative withdrawals since September 1, 2010. | |||||||||||||
Exelon Generation Co L L C [Member] | ' | ||||||||||||
Schedule Of Nuclear Decommissioning [Line Items] | ' | ||||||||||||
Nuclear decommissioning asset retirement obligation rollforward | ' | ||||||||||||
Nuclear decommissioning ARO at December 31, 2012 (a) | $ | 4,741 | |||||||||||
Accretion expense | 194 | ||||||||||||
Net decrease due to changes in, and timing of, estimated cash flows | -141 | ||||||||||||
Costs incurred to decommission retired plants | -2 | ||||||||||||
Nuclear decommissioning ARO at September 30, 2013 (a) | $ | 4,792 | |||||||||||
Unrealized Gains (Losses) on nuclear decommissioning trust funds | ' | ||||||||||||
Exelon and Generation | |||||||||||||
Three Months Ended | Nine Months Ended | ||||||||||||
September 30, | September 30, | ||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||
Net unrealized gains on decommissioning trust funds — | |||||||||||||
Regulatory Agreement Units (a) | $ | 103 | $ | 202 | $ | 196 | $ | 352 | |||||
Net unrealized gains on decommissioning trust funds — | |||||||||||||
Non-Regulatory Agreement Units (b)(c) | 46 | 71 | 70 | 101 | |||||||||
Zion Station pledged assets | ' | ||||||||||||
Exelon and Generation | |||||||||||||
September 30, | December 31, | ||||||||||||
2013 | 2012 | ||||||||||||
Carrying value of Zion Station pledged assets | $ | 486 | $ | 614 | |||||||||
Payable to Zion Solutions (a) | 443 | 564 | |||||||||||
Current portion of payable to Zion Solutions (b) | 104 | 132 | |||||||||||
Withdrawals by Zion Solutions to pay decommissioning costs (c) | 458 | 335 | |||||||||||
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. | |||||||||||||
Included in Other current liabilities within Exelon's and Generation's Consolidated Balance Sheets. | |||||||||||||
Cumulative withdrawals since September 1, 2010. | |||||||||||||
Retirement_Benefits_Tables
Retirement Benefits (Tables) | 9 Months Ended | |||||||||||||
Sep. 30, 2013 | ||||||||||||||
Retirement Benefits [Line Items] | ' | |||||||||||||
Schedule of Defined Benefit Plans Disclosures [Text Block] | ' | |||||||||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||||
Three Months Ended | Three Months Ended | |||||||||||||
September 30, | September 30, | |||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||
Service cost | $ | 79 | $ | 76 | $ | 41 | $ | 38 | ||||||
Interest cost | 163 | 181 | 48 | 53 | ||||||||||
Expected return on assets | -253 | -258 | -33 | -28 | ||||||||||
Amortization of: | ||||||||||||||
Transition obligation | 0 | 0 | 0 | 2 | ||||||||||
Prior service cost (benefit) | 3 | 5 | -4 | -3 | ||||||||||
Actuarial loss | 140 | 117 | 20 | 19 | ||||||||||
Settlement charges | 9 | 9 | 0 | 0 | ||||||||||
Curtailment gain | 0 | 0 | 0 | -5 | ||||||||||
Net periodic benefit cost | $ | 141 | $ | 130 | $ | 72 | $ | 76 | ||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||||
Nine Months Ended | Nine Months Ended | |||||||||||||
September 30, | September 30, | |||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||
Service cost | $ | 238 | $ | 211 | $ | 122 | $ | 114 | ||||||
Interest cost | 488 | 524 | 145 | 157 | ||||||||||
Expected return on assets | -761 | -742 | -99 | -86 | ||||||||||
Amortization of: | ||||||||||||||
Transition obligation | 0 | 0 | 0 | 8 | ||||||||||
Prior service cost (benefit) | 10 | 12 | -14 | -10 | ||||||||||
Actuarial loss | 421 | 338 | 62 | 58 | ||||||||||
Settlement charges | 9 | 9 | 0 | 0 | ||||||||||
Contractual termination benefit cost (a) | 0 | 14 | 0 | 6 | ||||||||||
Curtailment gain | 0 | 0 | 0 | -7 | ||||||||||
Net periodic benefit cost | $ | 405 | $ | 366 | $ | 216 | $ | 240 | ||||||
ComEd and BGE established regulatory assets of $1 million and $4 million, respectively, for their portion of the second quarter 2012 contractual termination benefit charge. | ||||||||||||||
Schedule Of Pension And Other Postretirement Benefit Costs [Text Block] | ' | |||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||
September 30, | September 30, | |||||||||||||
Pension and Other Postretirement Benefit Costs | 2013 | 2012 | 2013 | 2012 | ||||||||||
Generation | $ | 87 | $ | 85 | $ | 259 | $ | 259 | ||||||
ComEd | 77 | 75 | 231 | 212 | ||||||||||
PECO | 11 | 12 | 32 | 38 | ||||||||||
BGE (a)(b) | 14 | 14 | 41 | 46 | ||||||||||
BSC (c) | 24 | 20 | 58 | 63 | ||||||||||
(b) BGE's pension and other postretirement benefit costs for the three and nine months ended September 30, 2012 includes a $3 million contractual termination benefit charge, which was recorded as a regulatory asset as of September 30, 2012. | ||||||||||||||
BGE's pension and postretirement benefit costs for the nine months ended September 30, 2012 include $12 million of costs incurred prior to the closing of Exelon's merger with Constellation on March 12, 2012. These amounts are not included in Exelon's net periodic benefit costs for the nine months ended September 30, 2012 shown in the first table of the Defined Benefit Pension and Other Postretirement Benefits section above. | ||||||||||||||
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 September 30, 2012, ComEd and BGE each recorded a regulatory asset of $1 million related to their BSC-billed portion of the second quarter 2012 contractual termination benefit charge. | ||||||||||||||
Schedule Of Defined Contributions [Text Block] | ' | |||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||
September 30, | September 30, | |||||||||||||
Savings Plan Matching Contributions | 2013 | 2012 | 2013 | 2012 | ||||||||||
Exelon | $ | 18 | $ | 19 | $ | 61 | $ | 55 | ||||||
Generation | 8 | 9 | 29 | 25 | ||||||||||
ComEd | 6 | 5 | 16 | 14 | ||||||||||
PECO | 2 | 2 | 6 | 5 | ||||||||||
BGE (a) | 1 | 1 | 5 | 5 | ||||||||||
BSC (b) | 1 | 2 | 5 | 6 | ||||||||||
BGE's matching contributions for the nine months ended September 30, 2012 include $1 million of costs incurred prior to the closing of Exelon's merger with Constellation on March 12, 2012, which is not included in Exelon's matching contributions for the nine months ended September 30, 2012. | ||||||||||||||
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. | ||||||||||||||
StockBased_Compensation_Plans_1
Stock-Based Compensation Plans (Tables) | 9 Months Ended | ||||||||||||
Sep. 30, 2013 | |||||||||||||
Stock-Based Compensation Plans [Line Items] | ' | ||||||||||||
Stock Based Compensation Components [Text Block] | ' | ||||||||||||
Three Months Ended | Nine Months Ended | ||||||||||||
September 30, | September 30, | ||||||||||||
Components of Stock-Based Compensation Expense | 2013 | 2012 | 2013 | 2012 | |||||||||
Performance share awards | $ | 12 | $ | 5 | $ | 41 | $ | 32 | |||||
Stock options | 1 | 2 | 3 | 13 | |||||||||
Restricted stock units | 13 | 12 | 49 | 41 | |||||||||
Other stock-based awards | 1 | 1 | 4 | 3 | |||||||||
Total stock-based compensation expense included in | |||||||||||||
operating and maintenance expense | 27 | 20 | 97 | 89 | |||||||||
Income tax benefit | -10 | -8 | -37 | -34 | |||||||||
Total after-tax stock-based compensation expense | $ | 17 | $ | 12 | $ | 60 | $ | 55 | |||||
Stock Based Compensation Expense Subsidiaries [Text Block] | ' | ||||||||||||
Three Months Ended | Nine Months Ended | ||||||||||||
September 30, | September 30, | ||||||||||||
Subsidiaries | 2013 | 2012 | 2013 | 2012 | |||||||||
Generation | $ | 10 | $ | 9 | $ | 38 | $ | 33 | |||||
ComEd | 3 | 2 | 7 | 9 | |||||||||
PECO | 1 | 1 | 4 | 4 | |||||||||
BGE (a) | 1 | 1 | 5 | 4 | |||||||||
BSC (b) | 12 | 7 | 43 | 39 | |||||||||
Total (c) | $ | 27 | $ | 20 | $ | 97 | $ | 89 | |||||
(a) BGE's stock-based compensation expense (pre-tax) for the nine months ended September 30, 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 nine months ended September 30, 2012 shown in the tables titled Components of Stock-Based Compensation Expense and Subsidiaries above. | |||||||||||||
(b) These amounts primarily represent amounts billed to Exelon's subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO and BGE amounts above. | |||||||||||||
(c) The stock-based compensation expense (pre-tax) for the three and nine months ended September 30, 2013 reflects the impact of changes to the retirement eligibility requirements for employees participating in the LTIP. In addition, the stock-based compensation expense at ComEd reflects the adoption of the ComEd Key Manager Long-Term Performance Program in 2013 for certain employees, which is not considered stock-based compensation expense under the applicable authoritative guidance. In 2012, these employees participated in the Exelon Restricted Stock Award Program. | |||||||||||||
Changes_in_Accumulated_Other_C1
Changes in Accumulated Other Comprehensive Income (Tables) | 9 Months Ended | |||||||||||||
Sep. 30, 2013 | ||||||||||||||
Accumulated Other Comprehensive Income Loss [Line Items] | ' | |||||||||||||
Schedule Of Accumulated Other Comprehensive Income Loss Table [Text Block] | ' | |||||||||||||
Gains and (Losses) on Cash Flow Hedges | Unrealized Gains and (Losses) on Marketable Securities | Pension and Non-Pension Postretirement Benefit Plan items | Foreign Currency Items | AOCI of Equity Investments | Total | |||||||||
Exelon (a) | ||||||||||||||
Beginning balance | $ | 368 | $ | - | $ | -3,137 | $ | - | $ | 2 | $ | -2,767 | ||
OCI before reclassifications | 25 | -1 | 73 | -5 | 46 | 138 | ||||||||
Amounts reclassified from AOCI (b) | -194 | - | 157 | - | 5 | -32 | ||||||||
Net current-period OCI | -169 | -1 | 230 | -5 | 51 | 106 | ||||||||
Ending balance | $ | 199 | $ | -1 | $ | -2,907 | $ | -5 | $ | 53 | $ | -2,661 | ||
Generation (a) | ||||||||||||||
Beginning balance | $ | 512 | $ | - | $ | - | $ | - | $ | 1 | $ | 513 | ||
OCI before reclassifications | 12 | -1 | - | -5 | 47 | 53 | ||||||||
Amounts reclassified from AOCI (b) | -328 | - | - | - | 5 | -323 | ||||||||
Net current-period OCI | -316 | -1 | - | -5 | 52 | -270 | ||||||||
Ending balance | $ | 196 | $ | -1 | $ | - | $ | -5 | $ | 53 | $ | 243 | ||
ComEd (a) | ||||||||||||||
PECO (a) | ||||||||||||||
Beginning balance | $ | - | $ | 1 | $ | - | $ | - | $ | - | $ | 1 | ||
OCI before reclassifications | - | - | - | - | - | - | ||||||||
Amounts reclassified from AOCI (b) | - | - | - | - | - | - | ||||||||
Net current-period OCI | - | - | - | - | - | - | ||||||||
Ending balance | $ | - | $ | 1 | $ | - | $ | - | $ | - | $ | 1 | ||
BGE (a) | ||||||||||||||
(a) All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income. | ||||||||||||||
(b) See next table for details about these reclassifications. | ||||||||||||||
Earnings_Per_Share_and_Equity_1
Earnings Per Share and Equity (Tables) | 9 Months Ended | ||||||||||||
Sep. 30, 2013 | |||||||||||||
Earnings Per Share and Equity Tables [Abstract] | ' | ||||||||||||
Reconciliation of basic and diluted earnings per share | ' | ||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||
Net income attributable to common shareholders | $ | 738 | $ | 296 | $ | 1,224 | $ | 782 | |||||
Average common shares outstanding — basic | 857 | 854 | 856 | 804 | |||||||||
Assumed exercise of stock options, performance share awards | |||||||||||||
and restricted stock | 3 | 3 | 4 | 2 | |||||||||
Average common shares outstanding — diluted | 860 | 857 | 860 | 806 |
Commitments_and_Contingencies_1
Commitments and Contingencies (Tables) | 9 Months Ended | |||||||||||||||||||||||||
Sep. 30, 2013 | ||||||||||||||||||||||||||
Commitments And Contingencies Tables Disclosure [Line Items] | ' | |||||||||||||||||||||||||
Energy Commitments [Text Block] | ' | |||||||||||||||||||||||||
Net Capacity | REC | Transmission Rights | Purchased Energy | |||||||||||||||||||||||
Purchases (a) | Purchases (b) | Purchases (c) | from CENG | Total | ||||||||||||||||||||||
2013 | $ | 86 | $ | 17 | $ | 7 | $ | 186 | $ | 296 | ||||||||||||||||
2014 | 396 | 124 | 26 | 745 | 1,291 | |||||||||||||||||||||
2015 | 368 | 97 | 13 | — | 478 | |||||||||||||||||||||
2016 | 285 | 57 | 2 | — | 344 | |||||||||||||||||||||
2017 | 223 | 16 | 2 | — | 241 | |||||||||||||||||||||
Thereafter | 526 | 5 | 34 | — | 565 | |||||||||||||||||||||
Total | $ | 1,884 | $ | 316 | $ | 84 | $ | 931 | $ | 3,215 | ||||||||||||||||
(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 September 30, 2013, net of fixed capacity payments expected to be received by Generation under contracts to resell such acquired capacity to third parties under long-term capacity sale contracts. These capacity payments represent the fixed, or pre-determined, payment for output from contracted generation facilities. Output in this context generally includes products such as energy, capacity, and various ancillary services associated with generating facilities. Expected payments include certain capacity charges which are contingent on plant availability. | ||||||||||||||||||||||||||
(b) Power-related purchases include firm REC purchase agreements. 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 [Text Block] | ' | |||||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||||
2018 | ||||||||||||||||||||||||||
Total | 2013 | 2014 | 2015 | 2016 | 2017 | and beyond | ||||||||||||||||||||
ComEd | ||||||||||||||||||||||||||
Electric supply procurement (a) | $ | 878 | $ | 142 | $ | 323 | $ | 136 | $ | 137 | $ | 140 | $ | - | ||||||||||||
Renewable energy and RECs (b) | 1,604 | 20 | 67 | 74 | 76 | 77 | 1,290 | |||||||||||||||||||
PECO | ||||||||||||||||||||||||||
Electric supply procurement (c) | 886 | 211 | 584 | 91 | - | - | - | |||||||||||||||||||
AECs | 15 | 1 | 2 | 2 | 2 | 2 | 6 | |||||||||||||||||||
BGE | ||||||||||||||||||||||||||
Electric supply procurement (d) | 1,122 | 227 | 669 | 226 | - | - | - | |||||||||||||||||||
Curtailment services (e) | 147 | 13 | 46 | 41 | 34 | 13 | - | |||||||||||||||||||
(a) ComEd entered into various contracts for the procurement of electricity that started to expire in 2012, and will continue to expire through 2017. ComEd is permitted to recover its electric supply procurement costs from retail customers with no mark-up. See Note 5 – Regulatory Matters for additional information. | ||||||||||||||||||||||||||
(b) ComEd entered into 20-year contracts for renewable energy and RECs beginning June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. Pursuant to the ICC's Order on December 19, 2012, ComEd's commitments under the existing long-term contracts for energy and associated RECs were reduced in the first quarter of 2013. See Note 5 – Regulatory Matters for additional information. | ||||||||||||||||||||||||||
(c) PECO entered into various contracts for the procurement of electric supply to serve its default service customers that expire between 2013 and 2015. PECO is permitted to recover its electric supply procurement costs from default service customers with no mark-up in accordance with its PAPUC-approved DSP Programs. See Note 5 - Regulatory Matters for additional information. | ||||||||||||||||||||||||||
(d) BGE entered into various contracts for the procurement of electricity that expire between 2013 and 2015. The cost of power under these contracts is recoverable under MDPSC approved fuel clauses. See Note 5 - Regulatory Matters for additional information. | ||||||||||||||||||||||||||
(e) BGE has entered into various contracts with curtailment services providers related to transactions in PJM's capacity market. See Note 5 - Regulatory Matters for additional information. | ||||||||||||||||||||||||||
Fuel Purchase Commitments [Text Block] | ' | |||||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||||
2018 | ||||||||||||||||||||||||||
Total | 2013 | 2014 | 2015 | 2016 | 2017 | and beyond | ||||||||||||||||||||
Generation | $ | 7,901 | $ | 339 | $ | 1,199 | $ | 1,233 | $ | 1,021 | $ | 1,050 | $ | 3,059 | ||||||||||||
PECO | 477 | 54 | 128 | 100 | 78 | 36 | 81 | |||||||||||||||||||
BGE | 603 | 46 | 123 | 52 | 51 | 50 | 281 | |||||||||||||||||||
Schedule of Business Acquisitions by Acquisition, Contingent Consideration [Table Text Block] | ' | |||||||||||||||||||||||||
Description | Payment Period | BGE | Generation | Exelon | Statement of Operations Location | |||||||||||||||||||||
BGE rate credit of $100 per residential customer (a) | Q2 2012 | $ | 113 | $ | 0 | $ | 113 | Revenues | ||||||||||||||||||
Customer investment fund to invest in energy efficiency | ||||||||||||||||||||||||||
and low-income energy assistance to BGE customers | 2012 to 2014 | 0 | 0 | 113.5 | O&M Expense | |||||||||||||||||||||
Contribution for renewable energy, energy efficiency | ||||||||||||||||||||||||||
or related projects in Baltimore | 2012 to 2014 | 0 | 0 | 2 | O&M Expense | |||||||||||||||||||||
Charitable contributions at $7 million per year for 10 years | 2012 to 2021 | 28 | 35 | 70 | O&M Expense | |||||||||||||||||||||
State funding for offshore wind development projects | Q2 2012 | 0 | 0 | 32 | O&M Expense | |||||||||||||||||||||
Miscellaneous tax benefits | Q2 2012 | -2 | 0 | -2 | Taxes Other Than Income | |||||||||||||||||||||
Total | $ | 139 | $ | 35 | $ | 328.5 | ||||||||||||||||||||
____________________ | ||||||||||||||||||||||||||
(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. | ||||||||||||||||||||||||||
Commercial Commitments [Text Block] | ' | |||||||||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||||||||
Letters of credit (non-debt) (a) | $ | 1,514 | $ | 1,463 | $ | 26 | $ | 22 | $ | 1 | ||||||||||||||||
Guarantees | 4,908 | (b) | 1,271 | (c) | 209 | (d) | 181 | (e) | 252 | (f) | ||||||||||||||||
Nuclear insurance premiums (g) | 3,096 | 3,096 | 0 | 0 | 0 | |||||||||||||||||||||
Total commercial commitments | $ | 9,518 | $ | 5,830 | $ | 235 | $ | 203 | $ | 253 | ||||||||||||||||
(a) Non-debt letters of credit maintained to provide credit support for certain transactions as requested by third parties. | ||||||||||||||||||||||||||
(b) Primarily reflects parental guarantees issued on behalf of Generation to allow the flexibility needed to conduct business with counterparties without having to post other forms of collateral. Also reflects guarantees issued to ensure performance under specific contracts, preferred securities of financing trusts, property leases, indemnifications, NRC minimum funding assurance requirements and $211 million on behalf of CENG nuclear generating facilities for credit support and miscellaneous guarantees. The estimated net exposure for obligations under commercial transactions covered by these guarantees was $0.6 billion at September 30, 2013, which represents the total amount Exelon could be required to fund based on September 30, 2013 market prices. | ||||||||||||||||||||||||||
(c) Primarily reflects guarantees issued to ensure performance under energy marketing and other specific contracts and $211 million on behalf of CENG nuclear generating facilities for credit support. The estimated net exposure for obligations under commercial transactions covered by these guarantees was $0.2 billion at September 30, 2013, which represents the total amount Generation could be required to fund based on September 30, 2013 market prices. | ||||||||||||||||||||||||||
(d) Primarily reflects full and unconditional guarantees of $200 million Trust Preferred Securities of ComEd Financing III, which is a 100% owned finance subsidiary of ComEd. | ||||||||||||||||||||||||||
(e) Primarily reflects full and unconditional guarantees of $178 million Trust Preferred Securities of PECO Trust III and IV, which are 100% owned finance subsidiaries of PECO. | ||||||||||||||||||||||||||
(f) Primarily reflects full and unconditional guarantees of $250 million Trust Preferred Securities of BGE Capital Trust II, which is a 100% owned finance subsidiary of BGE. | ||||||||||||||||||||||||||
(g) 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. | ||||||||||||||||||||||||||
Accrued environmental liabilities [Text Block] | ' | |||||||||||||||||||||||||
30-Sep-13 | Total Environmental Investigation and Remediation Reserve | Portion of Total Related to MGP Investigation and Remediation | ||||||||||||||||||||||||
Exelon | $ | 345 | $ | 280 | ||||||||||||||||||||||
Generation | 56 | 0 | ||||||||||||||||||||||||
ComEd | 237 | 232 | ||||||||||||||||||||||||
PECO | 51 | 48 | ||||||||||||||||||||||||
BGE | 1 | 0 | ||||||||||||||||||||||||
31-Dec-12 | Total Environmental Investigation and Remediation Reserve | Portion of Total Related to MGP Investigation and Remediation | ||||||||||||||||||||||||
Exelon | $ | 351 | $ | 298 | ||||||||||||||||||||||
Generation | 42 | 0 | ||||||||||||||||||||||||
ComEd | 261 | 254 | ||||||||||||||||||||||||
PECO | 47 | 44 | ||||||||||||||||||||||||
BGE | 1 | 0 | ||||||||||||||||||||||||
Other Purchase Obligation [Table Text Block] | ' | |||||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||||
2018 | ||||||||||||||||||||||||||
Total | 2013 | 2014 | 2015 | 2016 | 2017 | and beyond | ||||||||||||||||||||
Exelon | $ | 269 | $ | 33 | $ | 38 | $ | 32 | $ | 31 | $ | 31 | $ | 104 | ||||||||||||
Generation | 628 | 133 | 178 | 127 | 40 | 38 | 112 | |||||||||||||||||||
ComEd (a) | 82 | 7 | 41 | 5 | 5 | 5 | 19 | |||||||||||||||||||
PECO (a) | 54 | 19 | 25 | 1 | 1 | 1 | 7 | |||||||||||||||||||
BGE (a) | 25 | 2 | 21 | 2 | — | — | — | |||||||||||||||||||
(a) Purchase obligations include commitments related to smart meter installation. See Note 5 - Regulatory Matters for additional information. | ||||||||||||||||||||||||||
Supplemental_Financial_Informa1
Supplemental Financial Information (Tables) | 9 Months Ended | ||||||||||||||||||
Sep. 30, 2013 | Sep. 30, 2012 | ||||||||||||||||||
Supplemental Financial Information Tables [Line Items] | ' | ' | |||||||||||||||||
Components of non-operating income and expenses | ' | ' | |||||||||||||||||
Three Months Ended September 30, 2013 | Exelon | Generation | ComEd | PECO | BGE | __________ | |||||||||||||
Other, Net | (a) Includes investment income and realized gains and losses on sales of investments of the trust funds. | ||||||||||||||||||
Decommissioning-related activities: | (b) Includes the elimination of NDT fund-related activity for the Regulatory Agreement Units, including the elimination of net income taxes related to all NDT fund activity for those units. See Note 13 – Asset Retirement Obligations of the Exelon 2012 Form 10-K for additional information regarding the accounting for nuclear decommissioning. | ||||||||||||||||||
Net realized income on decommissioning trust funds (a) | (c) Relates to the cash return on BGE's rate stabilization deferral. See Note 5 - Regulatory Matters for additional information regarding the rate stabilization deferral. | ||||||||||||||||||
Regulatory agreement units | $ | 138 | $ | 138 | $ | 0 | $ | 0 | $ | 0 | |||||||||
Non-regulatory agreement units | 35 | 35 | 0 | 0 | 0 | ||||||||||||||
Net unrealized gains on decommissioning trust funds | |||||||||||||||||||
Regulatory agreement units | 103 | 103 | 0 | 0 | 0 | ||||||||||||||
Non-regulatory agreement units | 46 | 46 | 0 | 0 | 0 | ||||||||||||||
Net unrealized losses on pledged assets | |||||||||||||||||||
Zion Station decommissioning | -9 | -9 | 0 | 0 | 0 | ||||||||||||||
Regulatory offset to decommissioning trust fund-related | |||||||||||||||||||
activities(b) | -189 | -189 | 0 | 0 | 0 | ||||||||||||||
Total decommissioning-related activities | 124 | 124 | 0 | 0 | 0 | ||||||||||||||
Investment income | 1 | 0 | 0 | 0 | 2 | (c) | |||||||||||||
Long-term lease income | 7 | 0 | 0 | 0 | 0 | ||||||||||||||
AFUDC - Equity | 4 | 0 | 2 | 1 | 1 | ||||||||||||||
Other | 19 | 10 | 5 | 0 | 1 | ||||||||||||||
Other, net | $ | 155 | $ | 134 | $ | 7 | $ | 1 | $ | 4 | |||||||||
Nine Months Ended September 30, 2013 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Other, Net | |||||||||||||||||||
Decommissioning-related activities: | |||||||||||||||||||
Net realized income on decommissioning trust funds (a) | |||||||||||||||||||
Regulatory agreement units | $ | 221 | $ | 221 | $ | 0 | $ | 0 | $ | 0 | |||||||||
Non-regulatory agreement units | 65 | 65 | 0 | 0 | 0 | ||||||||||||||
Net unrealized gains on decommissioning trust funds | |||||||||||||||||||
Regulatory agreement units | 196 | 196 | 0 | 0 | 0 | ||||||||||||||
Non-regulatory agreement units | 70 | 70 | 0 | 0 | 0 | ||||||||||||||
Net unrealized losses on pledged assets | |||||||||||||||||||
Zion Station decommissioning | -5 | -5 | 0 | 0 | 0 | ||||||||||||||
Regulatory offset to decommissioning trust fund-related | |||||||||||||||||||
activities(b) | -338 | -338 | 0 | 0 | 0 | ||||||||||||||
Total decommissioning-related activities | 209 | 209 | 0 | 0 | 0 | ||||||||||||||
Investment income (expense) | 6 | -1 | 0 | -1 | 7 | (c) | |||||||||||||
Long-term lease income | 20 | 0 | 0 | 0 | 0 | ||||||||||||||
Interest income related to uncertain income tax positions | 24 | 3 | 0 | 1 | 0 | ||||||||||||||
AFUDC - Equity | 16 | 0 | 8 | 3 | 5 | ||||||||||||||
Other | 36 | 18 | 10 | 1 | 1 | ||||||||||||||
Other, net | $ | 311 | $ | 229 | $ | 18 | $ | 4 | $ | 13 | |||||||||
Three Months Ended September 30, 2012 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Other, Net | |||||||||||||||||||
Decommissioning-related activities: | |||||||||||||||||||
Net realized income on decommissioning trust funds (a) | |||||||||||||||||||
Regulatory agreement units | $ | 33 | $ | 33 | $ | 0 | $ | 0 | $ | 0 | |||||||||
Non-regulatory agreement units | 10 | 10 | 0 | 0 | 0 | ||||||||||||||
Net unrealized gains on decommissioning trust funds | |||||||||||||||||||
Regulatory agreement units | 202 | 202 | 0 | 0 | 0 | ||||||||||||||
Non-regulatory agreement units | 71 | 71 | 0 | 0 | 0 | ||||||||||||||
Net unrealized gains on pledged assets | |||||||||||||||||||
Zion Station decommissioning | 22 | 22 | 0 | 0 | 0 | ||||||||||||||
Regulatory offset to decommissioning trust fund-related | |||||||||||||||||||
activities(b) | -208 | -208 | 0 | 0 | 0 | ||||||||||||||
Total decommissioning-related activities | 130 | 130 | 0 | 0 | 0 | ||||||||||||||
Investment income | 5 | 1 | 0 | 0 | 3 | ||||||||||||||
Long-term lease income | 7 | 0 | 0 | 0 | 0 | ||||||||||||||
Interest income related to uncertain income tax positions | 0 | 1 | 1 | 0 | 0 | ||||||||||||||
Credit facility termination fees | -43 | -43 | 0 | 0 | 0 | ||||||||||||||
AFUDC - Equity | 4 | 0 | 1 | 1 | 2 | ||||||||||||||
Other | -2 | -6 | 3 | 1 | 0 | ||||||||||||||
Other, net | $ | 101 | $ | 83 | $ | 5 | $ | 2 | $ | 5 | |||||||||
Nine Months Ended September 30, 2012 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Other, Net | |||||||||||||||||||
Decommissioning-related activities: | |||||||||||||||||||
Net realized income on decommissioning trust funds (a) | |||||||||||||||||||
Regulatory agreement units | $ | 143 | $ | 143 | $ | 0 | $ | 0 | $ | 0 | |||||||||
Non-regulatory agreement units | 77 | 77 | 0 | 0 | 0 | ||||||||||||||
Net unrealized gains on decommissioning trust funds | |||||||||||||||||||
Regulatory agreement units | 352 | 352 | 0 | 0 | 0 | ||||||||||||||
Non-regulatory agreement units | 101 | 101 | 0 | 0 | 0 | ||||||||||||||
Net unrealized gains on pledged assets | |||||||||||||||||||
Zion Station decommissioning | 60 | 60 | 0 | 0 | 0 | ||||||||||||||
Regulatory offset to decommissioning trust fund-related | |||||||||||||||||||
activities(b) | -453 | -453 | 0 | 0 | 0 | ||||||||||||||
Total decommissioning-related activities | 280 | 280 | 0 | 0 | 0 | ||||||||||||||
Investment income | 15 | 2 | 1 | 2 | 9 | ||||||||||||||
Long-term lease income | 22 | 0 | 0 | 0 | 0 | ||||||||||||||
Interest income related to uncertain income tax positions | 14 | 1 | 1 | 0 | 0 | ||||||||||||||
Credit facility termination fees | -85 | -85 | 0 | 0 | 0 | ||||||||||||||
AFUDC - Equity | 11 | 0 | 2 | 3 | 8 | ||||||||||||||
Other | -4 | -13 | 8 | 1 | 1 | ||||||||||||||
Other, net | $ | 253 | $ | 185 | $ | 12 | $ | 6 | $ | 18 | |||||||||
__________ | |||||||||||||||||||
(a) Includes investment income and realized gains and losses on sales of investments of the trust funds. | |||||||||||||||||||
(b) Includes the elimination of NDT fund-related activity for the Regulatory Agreement Units, including the elimination of net income taxes related to all NDT fund activity for those units. See Note 13 – Asset Retirement Obligations of the Exelon 2012 Form 10-K for additional information regarding the accounting for nuclear decommissioning. | |||||||||||||||||||
(c) Relates to the cash return on BGE's rate stabilization deferral. See Note 5 - Regulatory Matters for additional information regarding the rate stabilization deferral. | |||||||||||||||||||
Components of depreciation, amortization and accretion, and other, net | ' | ' | |||||||||||||||||
Nine Months Ended September 30, 2013 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Depreciation, amortization, accretion and depletion | |||||||||||||||||||
Property, plant and equipment | $ | 1,420 | $ | 610 | $ | 413 | $ | 164 | $ | 194 | |||||||||
Regulatory assets | 153 | 0 | 88 | 7 | 58 | ||||||||||||||
Amortization of intangible assets, net | 33 | 33 | 0 | 0 | 0 | ||||||||||||||
Amortization of energy contract assets and liabilities (a) | 342 | 398 | 0 | 0 | 0 | ||||||||||||||
Nuclear fuel (a) | 689 | 689 | 0 | 0 | 0 | ||||||||||||||
ARO accretion (b) | 207 | 207 | 0 | 0 | 0 | ||||||||||||||
Total depreciation, amortization, accretion and depletion | $ | 2,844 | $ | 1,937 | $ | 501 | $ | 171 | $ | 252 | |||||||||
Nine Months Ended September 30, 2012 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Depreciation, amortization, accretion and depletion | |||||||||||||||||||
Property, plant and equipment | $ | 1,263 | $ | 540 | $ | 396 | $ | 154 | $ | 184 | |||||||||
Regulatory assets | 89 | 0 | 62 | 7 | 34 | ||||||||||||||
Amortization of intangible assets, net | 24 | 24 | 0 | 0 | 0 | ||||||||||||||
Amortization of energy contract assets and liabilities (a) | 731 | 812 | 0 | 0 | 0 | ||||||||||||||
Nuclear fuel (a) | 628 | 628 | 0 | 0 | 0 | ||||||||||||||
ARO accretion (b) | 174 | 174 | 0 | 0 | 0 | ||||||||||||||
Total depreciation, amortization, accretion and depletion | $ | 2,909 | $ | 2,178 | $ | 458 | $ | 161 | $ | 218 | |||||||||
__________ | |||||||||||||||||||
(a) Included in revenues or fuel expense, or operating revenues on the Registrants' Consolidated Statements of Operations and Comprehensive Income. | |||||||||||||||||||
(b) Included in operating and maintenance expense on the Registrants' Consolidated Statements of Operations. | |||||||||||||||||||
Cash Flow Supplemental Disclosures | ' | ' | |||||||||||||||||
Nine Months Ended September 30, 2013 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Other non-cash operating activities: | |||||||||||||||||||
Pension and non-pension postretirement benefit costs | $ | 621 | $ | 259 | $ | 231 | $ | 32 | $ | 41 | |||||||||
Loss in equity method investments | -7 | -7 | 0 | 0 | 0 | ||||||||||||||
Provision for uncollectible accounts | 83 | 16 | -6 | 48 | 25 | ||||||||||||||
Stock-based compensation costs | 99 | 0 | 0 | 0 | 0 | ||||||||||||||
Other decommissioning-related activity (a) | -110 | -110 | 0 | 0 | 0 | ||||||||||||||
Energy-related options (b) | 87 | 87 | 0 | 0 | 0 | ||||||||||||||
Amortization of regulatory asset related to debt costs | 9 | 0 | 7 | 2 | 0 | ||||||||||||||
Amortization of rate stabilization deferral | 49 | 0 | 0 | 0 | 49 | ||||||||||||||
Amortization of debt fair value adjustment | -28 | -28 | 0 | 0 | 0 | ||||||||||||||
Discrete impacts from EIMA (c) | -206 | 0 | -206 | 0 | 0 | ||||||||||||||
Amortization of debt costs | 13 | 7 | 3 | 2 | 1 | ||||||||||||||
Merger integration costs (d) | -6 | 0 | 0 | 0 | -6 | ||||||||||||||
Impairment of investments in direct financing leases (e) | 14 | 0 | 0 | 0 | 0 | ||||||||||||||
Increase in inventory reserve | 7 | 7 | 0 | 0 | 0 | ||||||||||||||
Impairment charges (f) | 149 | 149 | 0 | 0 | 0 | ||||||||||||||
Other | -36 | -5 | -3 | 0 | -5 | ||||||||||||||
Total other non-cash operating activities | $ | 738 | $ | 375 | $ | 26 | $ | 84 | $ | 105 | |||||||||
Changes in other assets and liabilities: | |||||||||||||||||||
Under/over-recovered energy and transmission costs | $ | -47 | $ | 0 | $ | -63 | $ | -10 | $ | 26 | |||||||||
Other regulatory assets and liabilities | -50 | 0 | -35 | 0 | -85 | ||||||||||||||
Settlement of interest rate swaps (j) | 26 | 0 | 0 | 0 | 0 | ||||||||||||||
Other current assets | -169 | -123 | -3 | -31 | -35 | ||||||||||||||
Other noncurrent assets and liabilities | 205 | -40 | 261 | (g) | -6 | -25 | |||||||||||||
Total changes in other assets and liabilities | $ | -35 | $ | -163 | $ | 160 | $ | -47 | $ | -119 | |||||||||
Non-cash investing and financing activities: | |||||||||||||||||||
Consolidated VIE dividend to non-controlling interest | $ | 63 | $ | 63 | $ | 0 | $ | 0 | $ | 0 | |||||||||
Indemnification of like-kind exchange position (h) | 0 | 0 | 175 | 0 | 0 | ||||||||||||||
Total non-cash investing and financing activities: | $ | 63 | $ | 63 | $ | 175 | $ | 0 | $ | 0 | |||||||||
Nine Months Ended September 30, 2012 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Other non-cash operating activities: | |||||||||||||||||||
Pension and non-pension postretirement benefit costs | $ | 606 | $ | 259 | $ | 212 | $ | 38 | $ | 44 | |||||||||
Provision for uncollectible accounts | 120 | 14 | 38 | 46 | 28 | ||||||||||||||
Stock-based compensation costs | 75 | 0 | 0 | 0 | 0 | ||||||||||||||
Other decommissioning-related activity (a) | -108 | -108 | 0 | 0 | 0 | ||||||||||||||
Energy-related options (b) | 119 | 119 | 0 | 0 | 0 | ||||||||||||||
Amortization of regulatory asset related to debt costs | 13 | 0 | 10 | 2 | 1 | ||||||||||||||
Amortization of rate stabilization deferral | 39 | 0 | 0 | 0 | 49 | ||||||||||||||
Amortization of debt fair value adjustment | -49 | -23 | 0 | 0 | 0 | ||||||||||||||
Discrete impacts from EIMA (c) | 43 | 0 | 43 | 0 | 0 | ||||||||||||||
Merger-related commitments (i) | 179 | 35 | 0 | 0 | 28 | ||||||||||||||
Severance cost | 120 | 34 | 0 | 1 | 0 | ||||||||||||||
Loss in equity method investments | 69 | 69 | 0 | 0 | 0 | ||||||||||||||
Other | 9 | 23 | 7 | 9 | -2 | ||||||||||||||
Total other non-cash operating activities | $ | 1,235 | $ | 422 | $ | 310 | $ | 96 | $ | 148 | |||||||||
Changes in other assets and liabilities: | |||||||||||||||||||
Under/over-recovered energy and transmission costs | $ | 20 | $ | 0 | $ | 21 | $ | -3 | $ | 21 | |||||||||
Other regulatory assets and liabilities | -454 | 0 | -65 | 7 | -80 | ||||||||||||||
Other current assets | 52 | -85 | -8 | -56 | -25 | ||||||||||||||
Other noncurrent assets and liabilities | -40 | -110 | -72 | -5 | 7 | ||||||||||||||
Total changes in other assets and liabilities | $ | -422 | $ | -195 | $ | -124 | $ | -57 | $ | -77 | |||||||||
Non-cash investing and financing activities: | |||||||||||||||||||
Merger with Constellation, common stock issued | $ | 7,365 | $ | 5,258 | $ | 0 | $ | 0 | $ | 0 | |||||||||
_________ | |||||||||||||||||||
(a) Includes the elimination of NDT fund-related 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 13 of the Exelon 2012 Form 10-K 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 5 - Regulatory Matters for more information. | |||||||||||||||||||
(d) Relates to integration costs to achieve distribution synergies related to the merger transaction. See Note 5 - Regulatory Matters for more information. | |||||||||||||||||||
(e) Relates to an other than temporary decline in the estimated residual value of one of Exelon's direct financing leases. See Note 7 – Impairment of Long-Lived Assets for more information. | |||||||||||||||||||
(f) Relates to the cancellation of uprate projects and write down of certain wind projects at Generation. See Note 7 – Impairment of Long-Lived Assets for additional information. | |||||||||||||||||||
(g) Relates primarily to interest payable related to like-kind exchange tax position. See Note 12 – Income Taxes for discussion of the like-kind exchange tax position. | |||||||||||||||||||
(h) See Note 12 – Income Taxes for discussion of the like-kind exchange tax position. | |||||||||||||||||||
(i) See Note 4 - Mergers and Acquisitions for more information on merger-related commitments. | |||||||||||||||||||
(i) Relates to settlement of forward starting interest rate swaps that Exelon entered into in anticipation of the Continental Wind, LLC non-recourse project financing that was completed on September 30, 2013. See Note 10 – Derivative Financial Instruments for more information on interest rate swaps. | |||||||||||||||||||
Supplemental Balance Sheet Disclosures | ' | ' | |||||||||||||||||
30-Sep-13 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Property, plant and equipment: | |||||||||||||||||||
Accumulated depreciation and amortization | $ | 13,366 | (a) | $ | 6,848 | (a) | $ | 3,107 | $ | 2,914 | $ | 2,658 | |||||||
Accounts receivable: | |||||||||||||||||||
Allowance for uncollectible accounts | 302 | 72 | 73 | 119 | 38 | ||||||||||||||
31-Dec-12 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Property, plant and equipment: | |||||||||||||||||||
Accumulated depreciation and amortization | $ | 12,184 | (b) | $ | 6,014 | (b) | $ | 2,998 | $ | 2,797 | $ | 2,595 | |||||||
Accounts receivable: | |||||||||||||||||||
Allowance for uncollectible accounts | 293 | 84 | 70 | 99 | 40 | ||||||||||||||
___________ | |||||||||||||||||||
(a) Includes accumulated amortization of nuclear fuel in the reactor core of $2,365 million. | |||||||||||||||||||
(b) Includes accumulated amortization of nuclear fuel in the reactor core of $2,078 million. | |||||||||||||||||||
Segment_Information_Tables
Segment Information (Tables) | 9 Months Ended | ||||||||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||||||||
Schedules Of Segment Reporting Information [Line Items] | ' | ||||||||||||||||||||||
Analysis and reconciliation of reportable segment information | ' | ||||||||||||||||||||||
Three Months Ended September 30, 2013 and 2012 | |||||||||||||||||||||||
Intersegment Eliminations | |||||||||||||||||||||||
Generation (a) | ComEd | PECO | BGE | Other(b) | Exelon | ||||||||||||||||||
Total revenues(c): | |||||||||||||||||||||||
2013 | $ | 4,255 | $ | 1,156 | $ | 728 | $ | 737 | $ | 294 | $ | -668 | $ | 6,502 | |||||||||
2012 | 4,031 | 1,484 | 806 | 720 | 336 | -798 | 6,579 | ||||||||||||||||
Intersegment revenues(d): | |||||||||||||||||||||||
2013 | $ | 373 | $ | 1 | $ | 1 | $ | 2 | $ | 294 | $ | -669 | $ | 2 | |||||||||
2012 | 459 | 0 | 1 | 4 | 337 | -798 | 3 | ||||||||||||||||
Net income (loss): | |||||||||||||||||||||||
2013 | $ | 485 | $ | 126 | $ | 92 | $ | 53 | $ | -20 | $ | 0 | $ | 736 | |||||||||
2012 | 87 | 90 | 123 | 0 | -3 | 0 | 297 | ||||||||||||||||
Total assets: | |||||||||||||||||||||||
30-Sep-13 | $ | 40,498 | $ | 23,686 | $ | 9,745 | $ | 7,657 | $ | 9,563 | $ | -11,488 | $ | 79,661 | |||||||||
31-Dec-12 | 40,681 | 22,905 | 9,353 | 7,506 | 10,432 | -12,316 | 78,561 | ||||||||||||||||
__________ | |||||||||||||||||||||||
(a) Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions. Intersegment revenues for Generation for the three months ended September 30, 2013 include revenue from sales to PECO of $ 82 million and sales to BGE of $ 144 million in the Mid-Atlantic region, and sales to ComEd of $ 143 million in the Midwest. For the three months ended September 30, 2012 intersegment revenues for Generation include revenue from sales to PECO of $171 million and sales to BGE of $120 million in the Mid-Atlantic region, and sales to ComEd of $180 million in the Midwest region, net of $15 million related to the unrealized mark-to-market losses related to the ComEd swap, which eliminate upon consolidation. | |||||||||||||||||||||||
(b) Other primarily includes Exelon's corporate operations, shared service entities and other financing and investment activities. | |||||||||||||||||||||||
(c) For the three months ended September 30, 2013 and 2012, utility taxes of $21 million and $28 million, respectively, are included in revenues and expenses for Generation. For the three months ended September 30, 2013 and 2012, utility taxes of $65 million and $67 million, respectively, are included in revenues and expenses for ComEd. For the three months ended September 30, 2013 and 2012, utility taxes of $33 million and $40 million, respectively, are included in revenues and expenses for PECO. For the three months ended September 30, 2013 and 2012, utility taxes of $20 million and $20 million, respectively, are included in revenues and expenses for BGE. | |||||||||||||||||||||||
(d) Intersegment revenues exclude sales to unconsolidated affiliate entities. 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 Statements of Operations. | |||||||||||||||||||||||
Nine Months Ended September 30, 2013 and 2012 | |||||||||||||||||||||||
Intersegment Eliminations | |||||||||||||||||||||||
Generation (a) | ComEd | PECO | BGE(b) | Other(c) | Exelon | ||||||||||||||||||
Total revenues(d): | |||||||||||||||||||||||
2013 | $ | 11,858 | $ | 3,395 | $ | 2,295 | $ | 2,271 | $ | 909 | $ | -2,003 | $ | 18,725 | |||||||||
2012 | 10,539 | 4,154 | 2,396 | 1,388 | 1,049 | -2,291 | 17,235 | ||||||||||||||||
Intersegment revenues(e): | |||||||||||||||||||||||
2013 | $ | 1,083 | $ | 2 | $ | 1 | $ | 10 | $ | 909 | $ | -2,003 | $ | 2 | |||||||||
2012 | 1,233 | 2 | 3 | 7 | 1,050 | -2,291 | 4 | ||||||||||||||||
Net income (loss): | |||||||||||||||||||||||
2013 | $ | 795 | $ | 140 | $ | 292 | $ | 160 | $ | -152 | $ | 0 | $ | 1,235 | |||||||||
2012 | 419 | 219 | 300 | -50 | -101 | 0 | 787 | ||||||||||||||||
__________ | |||||||||||||||||||||||
(a) Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions. Intersegment revenues for Generation for the nine months ended September 30, 2013 include revenue from sales to PECO of $ 321 million and sales to BGE of $ 356 million in the Mid-Atlantic region, and sales to ComEd of $ 409 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 nine months ended September 30, 2012 intersegment revenues for Generation include revenue from sales to PECO of $407 million in the Mid-Atlantic region and sales to BGE of $223 million in the Mid-Atlantic region, and sales to ComEd of $631 million in the Midwest region, net of $30 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 September 30, 2012. | |||||||||||||||||||||||
(c) Other primarily includes Exelon's corporate operations, shared service entities and other financing and investment activities. | |||||||||||||||||||||||
(d) For the nine months ended September 30, 2013 and 2012, utility taxes of $60 million and $60 million, respectively, are included in revenues and expenses for Generation. For the nine months ended September 30, 2013 and 2012, utility taxes of $182 million and $182 million, respectively, are included in revenues and expenses for ComEd. For the nine months ended September 30, 2013 and 2012, utility taxes of $97 million and $108 million, respectively, are included in revenues and expenses for PECO. For the nine months ended September 30, 2013 and period of March 12, 2012 through September 30, 2012, utility taxes of $62 million and $42 million, respectively, are included in revenues and expenses for BGE. | |||||||||||||||||||||||
(e) Intersegment revenues exclude sales to unconsolidated affiliate entities. 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 Statements of Operations. | |||||||||||||||||||||||
Exelon Generation Co L L C [Member] | ' | ||||||||||||||||||||||
Schedules Of Segment Reporting Information [Line Items] | ' | ||||||||||||||||||||||
Analysis and reconciliation of reportable segment revenues for Generation | ' | ||||||||||||||||||||||
Three Months Ended September 30, 2013 and 2012 | |||||||||||||||||||||||
Generation total revenues (three months ended): | |||||||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||||
Revenues from external customers (a) | Intersegment revenues | Total Revenues | Revenues from external customers (a) | Intersegment revenues | Total Revenues | ||||||||||||||||||
Mid-Atlantic | $ | 1,381 | $ | 10 | $ | 1,391 | $ | 1,428 | $ | -11 | $ | 1,417 | |||||||||||
Midwest | 1,018 | -5 | 1,013 | 1,193 | 7 | 1,200 | |||||||||||||||||
New England | 341 | -1 | 340 | 390 | 1 | 391 | |||||||||||||||||
New York | 198 | -14 | 184 | 183 | 2 | 185 | |||||||||||||||||
ERCOT | 430 | -3 | 427 | 532 | 1 | 533 | |||||||||||||||||
Other Regions (b) | 278 | -7 | 271 | 317 | 12 | 329 | |||||||||||||||||
Total Revenues for Reportable Segments | 3,646 | -20 | 3,626 | 4,043 | 12 | 4,055 | |||||||||||||||||
Other (c) | 609 | 20 | 629 | -12 | -12 | -24 | |||||||||||||||||
Total Generation Consolidated Operating Revenues | $ | 4,255 | $ | 0 | $ | 4,255 | $ | 4,031 | $ | - | $ | 4,031 | |||||||||||
(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 $125 million and $404 million, for the three months ended September 30, 2013 and 2012, respectively, and elimination of intersegment revenues. | |||||||||||||||||||||||
Nine Months Ended September 30, 2013 and 2012 | |||||||||||||||||||||||
Generation total revenues (nine months ended): | |||||||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||||
Revenues from external customers (a) | Intersegment revenues | Total Revenues | Revenues from external customers (a) | Intersegment revenues | Total Revenues | ||||||||||||||||||
Mid-Atlantic | $ | 3,932 | $ | 11 | $ | 3,943 | $ | 3,832 | $ | -43 | $ | 3,789 | |||||||||||
Midwest | 3,274 | -3 | 3,271 | 3,600 | 19 | 3,619 | |||||||||||||||||
New England | 942 | -9 | 933 | 776 | 36 | 812 | |||||||||||||||||
New York | 547 | -20 | 527 | 394 | -22 | 372 | |||||||||||||||||
ERCOT | 1,042 | -8 | 1,034 | 1,073 | 1 | 1,074 | |||||||||||||||||
Other Regions (b) | 708 | 29 | 737 | 611 | 40 | 651 | |||||||||||||||||
Total Revenues for Reportable Segments | 10,445 | 0 | 10,445 | 10,286 | 31 | 10,317 | |||||||||||||||||
Other (c) | 1,413 | 0 | 1,413 | 253 | -31 | 222 | |||||||||||||||||
Total Generation Consolidated Operating Revenues | $ | 11,858 | $ | 0 | $ | 11,858 | $ | 10,539 | $ | 0 | $ | 10,539 | |||||||||||
(a) Includes all wholesale and retail electric 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 at the merger date of $603 million and $1,089 million, for the nine months ended September 30, 2013 and 2012, respectively, and elimination of intersegment revenues. | |||||||||||||||||||||||
Analysis and reconciliation of reportable segment revenues net of purchased power and fuel expense for Generation | ' | ||||||||||||||||||||||
Three Months Ended September 30, 2013 and 2012 | |||||||||||||||||||||||
Generation total revenues net of purchased power and fuel expense (three months ended): | |||||||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||||
RNF from external customers (a) | Intersegment RNF | Total RNF | RNF from external customers (a) | Intersegment RNF | Total RNF | ||||||||||||||||||
Mid-Atlantic | $ | 857 | $ | 7 | $ | 864 | $ | 919 | $ | -11 | $ | 908 | |||||||||||
Midwest | 606 | -5 | 601 | 723 | 7 | 730 | |||||||||||||||||
New England | 52 | 10 | 62 | 80 | 1 | 81 | |||||||||||||||||
New York | 29 | -38 | -9 | 11 | 2 | 13 | |||||||||||||||||
ERCOT | 222 | -78 | 144 | 158 | - | 158 | |||||||||||||||||
Other Regions (b) | 116 | -75 | 41 | 30 | 12 | 42 | |||||||||||||||||
Total Revenues net of purchased power and fuel expense for Reportable Segments | 1,882 | -179 | 1,703 | 1,921 | 11 | 1,932 | |||||||||||||||||
Other (c) | 194 | 179 | 373 | -12 | -11 | -23 | |||||||||||||||||
Total Generation Revenues net of purchased power and fuel expense | $ | 2,076 | $ | 0 | $ | 2,076 | $ | 1,909 | $ | - | $ | 1,909 | |||||||||||
(a) Includes purchases and sales from third parties and affiliated sales to ComEd, PECO and BGE. | |||||||||||||||||||||||
(b) Other regions includes 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 $44 million and $257 million for the three months ended September 30, 2013 and 2012, respectively. | |||||||||||||||||||||||
Nine Months Ended September 30, 2013 and 2012 | |||||||||||||||||||||||
Generation total revenues net of purchased power and fuel expense (nine months ended): | |||||||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||||
RNF from external customers (a) | Intersegment RNF | Total RNF | RNF from external customers (a) | Intersegment RNF | Total RNF | ||||||||||||||||||
Mid-Atlantic | $ | 2,477 | $ | -2 | $ | 2,475 | $ | 2,605 | $ | -44 | $ | 2,561 | |||||||||||
Midwest | 2,002 | -1 | 2,001 | 2,291 | 19 | 2,310 | |||||||||||||||||
New England | 156 | -14 | 142 | 144 | 36 | 180 | |||||||||||||||||
New York | 14 | -31 | -17 | 82 | -22 | 60 | |||||||||||||||||
ERCOT | 477 | -120 | 357 | 311 | 1 | 312 | |||||||||||||||||
Other Regions (b) | 238 | -91 | 147 | 49 | 41 | 90 | |||||||||||||||||
Total Revenues net of purchased power and fuel expense for Reportable Segments | 5,364 | -259 | 5,105 | 5,482 | 31 | 5,513 | |||||||||||||||||
Other (c) | 200 | 259 | 459 | 39 | -31 | 8 | |||||||||||||||||
Total Generation Revenues net of purchased power and fuel expense | $ | 5,564 | $ | 0 | $ | 5,564 | $ | 5,521 | $ | 0 | $ | 5,521 | |||||||||||
(a) Includes purchases and sales from third parties and affiliated sales to ComEd, PECO and BGE. | |||||||||||||||||||||||
(b) Other regions includes 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 at the merger date of $386 million and $793 million, for the nine months ended September 30, 2013 and 2012, respectively. |
Related_Party_Transactions_Tab
Related Party Transactions (Tables) | 9 Months Ended | ||||||
Sep. 30, 2013 | |||||||
Schedule Of Related Party Transactions By Related Party Tables [Line Items] | ' | ||||||
Schedule Of Income Loss From Equity Method Investments [Text Block] | ' | ||||||
Three Months | Three Months | ||||||
Ended September 30, | Ended September 30, | ||||||
2013 | 2012 | ||||||
Equity investment income | $ | 68 | $ | 58 | |||
Amortization of basis difference in CENG | -31 | -57 | |||||
Total equity in earnings - CENG | $ | 37 | $ | 1 | |||
Nine Months | For the Period March 12, | ||||||
Ended September 30, | through September 30, | ||||||
2013 | 2012 | ||||||
Equity investment income (loss) | $ | 93 | $ | 53 | |||
Amortization of basis difference in CENG | -88 | -131 | |||||
Total equity in earnings (losses) - CENG | $ | 5 | $ | -78 | |||
Exelon Generation Co L L C [Member] | ' | ||||||
Schedule Of Related Party Transactions By Related Party Tables [Line Items] | ' | ||||||
Schedule Of Income Loss From Equity Method Investments [Text Block] | ' | ||||||
Three Months | Three Months | ||||||
Ended September 30, | Ended September 30, | ||||||
2013 | 2012 | ||||||
Equity investment income | $ | 68 | $ | 58 | |||
Amortization of basis difference in CENG | -31 | -57 | |||||
Total equity in earnings - CENG | $ | 37 | $ | 1 | |||
Nine Months | For the Period March 12, | ||||||
Ended September 30, | through September 30, | ||||||
2013 | 2012 | ||||||
Equity investment income (loss) | $ | 93 | $ | 53 | |||
Amortization of basis difference in CENG | -88 | -131 | |||||
Total equity in earnings (losses) - CENG | $ | 5 | $ | -78 |
Significant_Accounting_Policie
Significant Accounting Policies (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Operating and maintenance | $1,735 | $2,170 | $5,391 | $5,979 |
Interest Expense | 228 | 240 | 1,091 | 678 |
Exelon Generation Co L L C [Member] | ' | ' | ' | ' |
Operating and maintenance | 936 | 1,289 | 2,943 | 3,319 |
Interest Expense | 82 | 85 | 257 | 223 |
Consolidation Percentages Detail Tagging [Abstract] | ' | ' | ' | ' |
Exelon Percentage ownership of Exelon SHC, LLC | 50.01% | ' | 50.01% | ' |
Commonwealth Edison Co [Member] | ' | ' | ' | ' |
Electrical transmission and distribution revenue | 1,155 | 1,484 | 3,393 | 4,152 |
Operating and maintenance | 296 | 313 | 907 | 882 |
Interest Expense | 71 | 71 | 493 | 221 |
PECO Energy Co [Member] | ' | ' | ' | ' |
Operating and maintenance | 162 | 172 | 480 | 491 |
Interest Expense | 26 | 29 | 77 | 85 |
Baltimore Gas and Electric Company [Member] | ' | ' | ' | ' |
Operating and maintenance | 125 | 172 | 391 | 460 |
Interest Expense | 29 | 35 | 94 | 110 |
Baltimore Gas and Electric Company [Member] | Scenario Adjustment [Member] | ' | ' | ' | ' |
Operating and maintenance | ' | ' | $4 | ' |
Basis_of_Presentation_Details
Basis of Presentation (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Depreciation and amortization | $530 | $500 | $1,606 | $1,376 |
Operating and maintenance | 1,735 | 2,170 | 5,391 | 5,979 |
Capital expenditures | ' | ' | 3,887 | 4,162 |
Exelon Generation Co L L C [Member] | ' | ' | ' | ' |
Depreciation and amortization | 218 | 207 | 643 | 564 |
Operating and maintenance | 936 | 1,289 | 2,943 | 3,319 |
Capital expenditures | ' | ' | 1,995 | 2,602 |
Commonwealth Edison Co [Member] | ' | ' | ' | ' |
Depreciation and amortization | 164 | 157 | 501 | 458 |
Operating and maintenance | 296 | 313 | 907 | 882 |
Capital expenditures | ' | ' | 1,074 | 896 |
PECO Energy Co [Member] | ' | ' | ' | ' |
Depreciation and amortization | 57 | 55 | 171 | 161 |
Operating and maintenance | 162 | 172 | 480 | 491 |
Capital expenditures | ' | ' | 374 | 274 |
Baltimore Gas and Electric Company [Member] | ' | ' | ' | ' |
Depreciation and amortization | 78 | 68 | 252 | 218 |
Operating and maintenance | 125 | 172 | 391 | 460 |
Capital expenditures | ' | ' | 391 | 419 |
Baltimore Gas and Electric Company [Member] | Scenario Adjustment [Member] | ' | ' | ' | ' |
Depreciation and amortization | ' | ' | 2 | ' |
Operating and maintenance | ' | ' | 4 | ' |
Capital expenditures | ' | ' | $17 | ' |
Variable_Interest_Entities_Det
Variable Interest Entities (Details) (USD $) | 9 Months Ended | 12 Months Ended | 3 Months Ended | 9 Months Ended | |||||||||||||||||||||||||||||||||||||||||
In Millions, unless otherwise specified | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | |||||||||||
VIE | VIE | Commercial Agreement Variable Interest Entities [Member] | Commercial Agreement Variable Interest Entities [Member] | Equity Method Investment Variable Interest Entities [Member] | Equity Method Investment Variable Interest Entities [Member] | Letter of Credit [Member] | Letter of Credit [Member] | Investments [Member] | Investments [Member] | Investments [Member] | Investments [Member] | Contract Intangible Asset [Member] | Contract Intangible Asset [Member] | Contract Intangible Asset [Member] | Contract Intangible Asset [Member] | Payment Guarantee [Member] | Payment Guarantee [Member] | Payment Guarantee [Member] | Payment Guarantee [Member] | Net assets pledged for Zion Station decommissioning | Net assets pledged for Zion Station decommissioning | Net assets pledged for Zion Station decommissioning | Net assets pledged for Zion Station decommissioning | Power Contract Monetization Entities [Member] | Variable Interes tEntity Primary Beneficiary [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | ||||||||||||
Maximum [Member] | Maximum [Member] | Maximum [Member] | Maximum [Member] | Maximum [Member] | Maximum [Member] | Maximum [Member] | Maximum [Member] | Maximum [Member] | Maximum [Member] | Maximum [Member] | Maximum [Member] | Maximum [Member] | Maximum [Member] | RSB Bond Co LLC [Member] | RSB Bond Co LLC [Member] | RSB Bond Co LLC [Member] | RSB Bond Co LLC [Member] | ||||||||||||||||||||||||||||
Commercial Agreement Variable Interest Entities [Member] | Equity Method Investment Variable Interest Entities [Member] | Equity Method Investment Variable Interest Entities [Member] | Commercial Agreement Variable Interest Entities [Member] | Commercial Agreement Variable Interest Entities [Member] | Equity Method Investment Variable Interest Entities [Member] | Equity Method Investment Variable Interest Entities [Member] | Commercial Agreement Variable Interest Entities [Member] | Commercial Agreement Variable Interest Entities [Member] | |||||||||||||||||||||||||||||||||||||
Consolidated Variable Interest Entities Disclosure [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||
Current assets | $391 | $550 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $330 | $519 | [1] | $50 | $30 | ' | ' | ' | ' | |||||||||
Noncurrent assets | 1,900 | 1,802 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,877 | 1,762 | [1] | ' | ' | 3 | ' | 3 | ' | |||||||||
Total Assets | 2,291 | 2,352 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,207 | 2,281 | [1] | 53 | 30 | ' | ' | ' | ' | |||||||||
Current liabilities | 453 | 685 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 366 | 613 | [1] | 77 | 71 | ' | ' | ' | ' | |||||||||
Noncurrent liabilities | 859 | 837 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 608 | 532 | [1] | 230 | 265 | ' | ' | ' | ' | |||||||||
Total Liabilities | 1,312 | 1,522 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 974 | 1,145 | [1] | 307 | 336 | ' | ' | ' | ' | |||||||||
Deferred tax assets | ' | 116 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||
Deferred tax liabilities | ' | 62 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 53 | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||
Remittance of payments received from customers for rate stabilization to BondCo. | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 24 | 27 | 63 | 62 | |||||||||||
Parental guarantee provided | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 75 | 75 | ' | ' | ' | ' | |||||||||||
Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||
Number of Variable Interest Entities not consolidated by equity holders | 7 | 9 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||
Number Of Variable Interest Entities Consolidated | 4 | 5 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||
Total assets | 481 | [2] | 740 | [2] | 115 | [2] | 386 | [2] | 366 | [2] | 354 | [2] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 146 | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Total liabilities | 129 | [2] | 333 | [2] | 3 | [2] | 219 | [2] | 126 | [2] | 114 | [2] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 42 | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Our ownership interest | 97 | [2] | 97 | [2] | ' | ' | 97 | [2] | 97 | [2] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||
Other ownership interests | 255 | [2] | 310 | [2] | 112 | [2] | 167 | [2] | 143 | [2] | 143 | [2] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Our maximum exposure to loss | ' | ' | ' | ' | ' | ' | 5 | 5 | 78 | 77 | 78 | 77 | 9 | 8 | 9 | 8 | 5 | 5 | 5 | 5 | 43 | [3] | 50 | [3] | 43 | [3] | 50 | [3] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information Footnotes [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||
Gross pledged assets | 486 | 614 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 486 | 614 | ' | ' | ' | ' | ' | ' | |||||||||||
Pledged assets liabilities offset | $443 | $564 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $443 | $564 | ' | ' | ' | ' | ' | ' | |||||||||||
[1] | Includes total assets of $146 million and total liabilities of $42 million as of December 31, 2012 related to a retail power supply company that is no longer a consolidated VIE as of September 30, 2013. | ||||||||||||||||||||||||||||||||||||||||||||
[2] | These items represent amounts on the unconsolidated VIE balance sheets, not on Exelonbs or Generationbs Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs. | ||||||||||||||||||||||||||||||||||||||||||||
[3] | These items represent amounts on Exelonbs and Generationbs Consolidated Balance Sheets related to the asset sale agreement with ZionSolutions, LLC. The net assets pledged for Zion Station decommissioning includes gross pledged assets of $486 million and $614 million as of September 30, 2013 and December 31, 2012, respectively; offset by payables to ZionSolutions LLC of $443 million and $564 million as of September 30, 2013 and December 31, 2012, respectively. These items are included to provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE. |
Regulatory_Matters_Details
Regulatory Matters (Details) (USD $) | 9 Months Ended | 9 Months Ended | 1 Months Ended | 9 Months Ended | 12 Months Ended | 9 Months Ended | 0 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2008 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Dec. 31, 2011 | Feb. 29, 2012 | Dec. 31, 2010 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Jun. 01, 2013 | Sep. 30, 2013 | Mar. 31, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | |||||||||||||||||||||||||||||||||||
Nuclear Decommissioning [Member] | Nuclear Decommissioning [Member] | Removal Costs [Member] | Removal Costs [Member] | Energy Efficiency Demand Response Programs [Member] | Energy Efficiency Demand Response Programs [Member] | Electric Transmission And Distribution Tax Repairs [Member] | Electric Transmission And Distribution Tax Repairs [Member] | Over Recovered Uncollectible Accounts Expense [Member] | Over Recovered Energy And Transmission Costs [Member] | Over Recovered Energy And Transmission Costs [Member] | Over-Recovered Universal Service Fund Costs [Member] | Over-Recovered Universal Service Fund Costs [Member] | Over-Recovered AEPS Costs [Member] | Revenue subject to refund [Member] | Revenue subject to refund [Member] | Over Recovered Decoupling Revenue [Member] | Over Recovered Decoupling Revenue [Member] | Gas Distribution Tax Repairs [Member] | Regulatory Liabilities Other [Member] | Dlc Program Cost [Member] | Energy Efficiency Phase [Member] | Pension and Other Postretirement Benefits [Member] | Pension and Other Postretirement Benefits [Member] | Deferred Income Taxes [Member] | Deferred Income Taxes [Member] | AMI Expenses [Member] | AMI Expenses [Member] | AMI Meter Events [Member] | AMI Meter Events [Member] | Under Recovered Distribution Service Costs [Member] | Under Recovered Distribution Service Costs [Member] | Debt Costs [Member] | Debt Costs [Member] | Fair Value Of Long Term Debt [Member] | Fair Value Of Long Term Debt [Member] | Fair Value Of Supply Contract [Member] | Fair Value Of Supply Contract [Member] | Severance [Member] | Severance [Member] | Asset Retirement Obligations [Member] | Asset Retirement Obligations [Member] | MGP Remediation Costs [Member] | MGP Remediation Costs [Member] | RTO Startup Costs [Member] | RTO Startup Costs [Member] | Under Recovered Universal Service Fund Costs Member [Member] | Under Recovered Universal Service Fund Costs Member [Member] | Under Recovered Uncollectible Accounts Expense [Member] | Financial Swap with Generation [Member] | Renewable Energy And Associated REC [Member] | Renewable Energy And Associated REC [Member] | Under Recovered Energy And Transmission Costs [Member] | Under Recovered Energy And Transmission Costs [Member] | DSP Program Electric Procurement Contracts [Member] | DSP II Program Electric Procurement Contracts [Member] | DSP Program costs [Member] | DSP II Program Costs [Member] | Deferred Storm Costs [Member] | Deferred Storm Costs [Member] | Electric Generation Related Regulatory Asset [Member] | Electric Generation Related Regulatory Asset [Member] | Rate Stabilization Deferral [Member] | Rate Stabilization Deferral [Member] | Energy Efficiency And Demand Response Programs [Member] | Energy Efficiency And Demand Response Programs [Member] | Under Recovered Decoupling Revenue [Member] | Under Recovered Decoupling Electric Revenue [Member] | Under Recovered Decoupling Electric Revenue [Member] | Merger Integration Costs [Member] | Other Regulatory Assets [Member] | Other Regulatory Assets [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Exelon Corporate [Member] | Exelon Corporate [Member] | |||||||||||||||||||||||||||||||||||||||
Regulatory Liabilities Other [Member] | Under Recovered Uncollectible Accounts Expense [Member] | Nuclear Decommissioning [Member] | Nuclear Decommissioning [Member] | Removal Costs [Member] | Removal Costs [Member] | Energy Efficiency Demand Response Programs [Member] | Energy Efficiency Demand Response Programs [Member] | Electric Transmission And Distribution Tax Repairs [Member] | Over Recovered Uncollectible Accounts Expense [Member] | Over Recovered Energy And Transmission Costs [Member] | Over Recovered Energy And Transmission Costs [Member] | Over-Recovered Universal Service Fund Costs [Member] | Over-Recovered AEPS Costs [Member] | Revenue subject to refund [Member] | Revenue subject to refund [Member] | Pension and Other Postretirement Benefits [Member] | Deferred Income Taxes [Member] | Deferred Income Taxes [Member] | AMI Expenses [Member] | AMI Expenses [Member] | AMI Meter Events [Member] | Under Recovered Distribution Service Costs [Member] | Under Recovered Distribution 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Regulatory Assets [Member] | Energy Efficiency And Demand Response Programs [Member] | Energy Efficiency And Demand Response Programs [Member] | MW | Nuclear Decommissioning [Member] | Removal Costs [Member] | Removal Costs [Member] | Energy Efficiency Demand Response Programs [Member] | Electric Transmission And Distribution Tax Repairs [Member] | Over Recovered Uncollectible Accounts Expense [Member] | Over Recovered Energy And Transmission Costs [Member] | Over Recovered Energy And Transmission Costs [Member] | Over Recovered Gas Energy And Transmission Costs [Member] | Over-Recovered Universal Service Fund Costs [Member] | Over-Recovered AEPS Costs [Member] | Over Recovered Decoupling Revenue [Member] | Over Recovered Decoupling Revenue [Member] | Over Recovered Decoupling Electric Revenue [Member] | Over Recovered Decoupling Gas Revenue [Member] | Over Recovered Decoupling Gas Revenue [Member] | Regulatory Liabilities Other [Member] | Over Recovered Electric Energy And Transmission Costs [Member] | Pension and Other Postretirement Benefits [Member] | Pension and Other Postretirement Benefits [Member] | Deferred Income Taxes [Member] | Deferred Income Taxes [Member] | AMI Expenses [Member] | AMI Expenses [Member] | AMI Meter Events [Member] | AMI Meter Events [Member] | Under Recovered Distribution Service Costs [Member] | Debt Costs [Member] | Debt Costs [Member] | Fair Value Of Long Term Debt [Member] | Fair Value Of Supply Contract [Member] | Severance [Member] | Severance [Member] | Asset Retirement Obligations [Member] | MGP Remediation Costs [Member] | MGP Remediation Costs [Member] | RTO Startup Costs [Member] | Under Recovered Universal Service Fund Costs Member [Member] | Under Recovered Uncollectible Accounts Expense [Member] | Financial Swap with Generation [Member] | Renewable Energy And Associated REC [Member] | Under Recovered Energy And Transmission Costs [Member] | Under Recovered Energy And Transmission Costs [Member] | Under Recovered Electric Energy And Transmission Costs [Member] | Under Recovered Gas Energy And Transmission Costs [Member] | DSP Program Electric Procurement Contracts [Member] | DSP Program Electric Procurement Contracts [Member] | DSP II Program Electric Procurement Contracts [Member] | DSP II Program Costs [Member] | Deferred Storm Costs [Member] | Deferred Storm Costs [Member] | Electric Generation Related Regulatory Asset [Member] | Electric Generation Related Regulatory Asset [Member] | Rate Stabilization Deferral [Member] | Rate Stabilization Deferral [Member] | Energy Efficiency And Demand Response Programs [Member] | Energy Efficiency And Demand Response Programs [Member] | Under Recovered Decoupling Revenue [Member] | Under Recovered Decoupling Electric Revenue [Member] | Under Recovered Decoupling Electric Revenue [Member] | Merger Integration Costs [Member] | Other Regulatory Assets [Member] | Other Regulatory Assets [Member] | Gas Distribution Tax Repairs [Member] | AMI Meter Events [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
SmartMeters | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Purchase Of Receivables [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
POR gross receivables | $285 | [1] | ' | $191 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $124 | [1] | ' | $55 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $78 | [1] | ' | $65 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $83 | [1] | ' | $71 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||
POR Allowance for uncollectible accounts | -31 | [2] | ' | -21 | [2] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -18 | [2] | ' | -9 | [2] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -7 | [2] | ' | -6 | [2] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -6 | [2] | ' | -6 | [2] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||
POR net receivables | 254 | ' | 170 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 106 | ' | 46 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 71 | ' | 59 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 77 | ' | 65 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Energy Infrastructure Modernization Act [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Current length of state legislation enacted | ' | '10 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Increased revenue requirement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 353 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Expected revenue adjustment for prior year | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 191 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Expected revenue adjustment for current year | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 162 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Excess basis points over treasury after year one | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5.80% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Senate Bill [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Next 6 months Projected Revenue | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 15 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Year 2 Projected Revenue | 65 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Next 12 months Projected CapEx | 40 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Year 2 Projected CapEx | 45 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Next 6 months estimated refund | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 14 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Illinois Settlement Agreement [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Annual energy savings requirement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Demand response peak demand reduction | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Distribution Rate Case [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Requested increase in electric revenues | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 396 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 101 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Adjustment to Requested increase in electric revenues | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 343 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Recovery request for Operating and Maintenance expenses of AMI Pilot Program | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 40 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Requested increase in gas revenues | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 30 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Requested rate of return on common equity | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 11.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Rate of return on common equity electric distribution | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.10% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9.75% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Rate of return on common equity gas distribution | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9.60% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Increase in electric delivery service revenue resulting from rate case settlement or order. | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 143 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 81 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Increase in gas delivery service revenue resulting from rate case settlement or order. | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 32 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Regulatory Assets Transfer Changes | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6 | 8 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Severance Recovered Through Distribution Rates | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
ComEd's proposed increase to net distribution revenue requirement related to uncollectable account expense | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 22 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Requested Rate Of Return Common Equity Electric Distribution | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.5 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.5 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Requested Rate Of Return Common Equity Gas Distribution | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.35 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Appeal of 2007 Illinois Electric Distribution Rate Case [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Increase in electric delivery service revenue requirement resulting from regulatory order in rate case | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 274 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Estimated Refund Obligation To Customers | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 37 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Annual Transmission Formula Rate Update [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Gross transmission revenue requirement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 488 | 450 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 158 | ' | 156 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Transmission revenue true up | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 25 | 5 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1 | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Net transmission revenue requirement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 513 | 445 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 157 | ' | 158 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Smart Meter and Smart Grid Investments [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Estimated number of smart meters to be installed | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Expected number of smart meters to be deployed during the first phase of Smart Meter Installment Plan | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Revised spend on its Smart Meter Procurement and Installation Plan | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 595 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Spend on smart grid investments | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 120 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Smart meter spend to date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 364 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Smart grid infrastructure spend to date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 111 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Total smart grid and smart meter investment grant amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 200 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Smart meter investment grant awarded | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 140 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Smart grid investment grant awarded | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 60 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 200 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Reimbursements received from the DOE | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 181 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 176 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Outstanding reimbursable DOE Smart Grid Investment Grant expenditures | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 23 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Regulatory assets for original smart meters purchased | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 17 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Carrying value of originally installed Smart Meters, net of reimbursements from DOE | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 19 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
VendorRefund | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Amount of reimbursements received from the DOE applied to the originally installed Smart Meters. | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 16 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Total Projected smart meter smart grid spend | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 480 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
New Electric Generation [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Megawatt capacity of new generating plant | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 700 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Energy Efficiency Program [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Cumulative Consumption Reduction Targets | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2.90% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Amount of cost recoveries sought under the Direct Load Control Program. | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 12 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Proposed funding of estimated costs associated with DLC demand program due to modification of incentive levels for other Phase II programs. | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Advanced metering infrastructure pilot program [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Collections Under Rider Amp | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 24 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Authorized Return On Rate Base [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Weighted Average Debt And Equity Return Electric Distribution | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.07% | 0.07% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Weighted Average Debt And Equity Return | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8.70% | 8.91% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8.35% | 8.43% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Rate Of Return On Common Equity | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 11.50% | ' | 0.09% | 0.09% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.80% | ' | 11.30% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Rate Of Return On Common Equity in FERC Complaint | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8.70% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Potential refund resulting from the FERC Comlaint | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Common Equity Component Cap | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 55.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Regulatory Assets And Liabilities Other Disclosures [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Over under recovered transmission costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Over under recovered electric supply costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 18 | ' | 47 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Over under recovered gas supply costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 13 | ' | 1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Amortization of rate stabilization deferral | 49 | 39 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 49 | 49 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Recovered portion of regulatory assets | 153 | 89 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' | 88 | 62 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7 | 7 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 58 | 34 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Regulatory Asset [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 6,509 | ' | 6,497 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,542 | 3,673 | 1,424 | 1,382 | 129 | 70 | 5 | 17 | 275 | 191 | 60 | 68 | 225 | [3] | 256 | [3] | 3 | [4] | 12 | [4] | 13 | 28 | 93 | 90 | 210 | 232 | 1 | 2 | 0 | ' | ' | 0 | 106 | 49 | 0 | ' | 0 | 0 | 3 | 2 | 4 | 6 | 33 | 40 | 175 | 225 | 144 | 126 | ' | ' | 0 | 10 | [5] | 26 | 25 | ' | ' | 31 | ' | 819 | ' | 666 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 65 | 62 | 29 | 10 | 0 | 275 | 191 | 56 | 62 | 0 | [3] | 0 | [4] | 0 | 0 | 12 | 68 | 65 | 175 | 197 | 1 | 2 | 0 | 31 | 0 | ' | 106 | 49 | 0 | ' | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | ' | 13 | 16 | 1,419 | ' | 1,378 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | 1,296 | 1,255 | 48 | 29 | 5 | 17 | 0 | 4 | 6 | 0 | [3] | 0 | [4] | ' | 0 | 0 | 25 | 25 | 34 | 33 | 0 | 0 | ' | 0 | 0 | 0 | 0 | 0 | 3 | 0 | 2 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | ' | 7 | 8 | ' | ' | ' | 509 | ' | 522 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | 63 | 65 | 52 | 31 | 0 | 0 | 0 | 9 | 9 | 0 | [3] | 0 | [4] | 13 | 16 | 0 | 1 | 2 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | ' | ' | 0 | 0 | 0 | 0 | 4 | 6 | 33 | 40 | 175 | 225 | 144 | 126 | ' | ' | 0 | 10 | [5] | 5 | 2 | ' | ' | |||||||||||||||||||||||
Current regulatory assets | 877 | ' | 764 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 308 | 304 | 12 | 14 | 4 | 3 | ' | ' | 129 | 18 | 12 | 14 | 0 | [3] | 0 | 29 | [4] | 77 | [4] | 23 | 29 | 0 | 0 | 47 | 58 | 2 | 3 | 0 | 11 | 0 | 0 | 16 | 18 | 79 | 43 | 0 | 0 | 1 | 1 | 3 | 3 | 13 | 16 | 68 | 67 | 75 | 56 | 5 | [6] | 8 | ' | 1 | [5] | 48 | 23 | ' | ' | ' | ' | 335 | ' | 388 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 3 | 5 | 4 | 3 | 0 | 129 | 18 | 9 | 11 | 0 | [3] | 0 | [4] | 0 | 19 | 25 | 0 | 0 | 40 | 51 | 2 | 3 | 0 | 0 | 0 | 226 | 16 | 18 | 79 | 14 | 0 | 0 | 0 | 0 | 0 | ' | 0 | 0 | 0 | 0 | 34 | 14 | 22 | ' | 32 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | 0 | ' | 0 | ' | 0 | ' | 0 | 3 | 3 | 0 | [3] | 0 | [4] | 0 | 0 | 0 | 0 | 0 | 6 | 6 | 0 | 0 | 11 | 0 | 0 | 0 | 1 | [7] | 0 | 1 | 0 | 1 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 13 | 9 | ' | ' | ' | 184 | ' | 190 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | 9 | 9 | 0 | 0 | 0 | 0 | 0 | 1 | 1 | 0 | [3] | 0 | [4] | 4 | 4 | 0 | 1 | 1 | 0 | 0 | 0 | 0 | 0 | 0 | 28 | [8] | 9 | 19 | 0 | 0 | 0 | 0 | 3 | 3 | 13 | 16 | 68 | 67 | 75 | 56 | 5 | [6] | 8 | 5 | 1 | [5] | 1 | 0 | ' | 0 | ||||||||||||||||||||
Net regulatory asset | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 404 | 209 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Regulatory Liabilities [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Regulatory Liability Current | 314 | ' | 368 | ' | 0 | 103 | 97 | 85 | 131 | 20 | 20 | 6 | 41 | 54 | 7 | 3 | 2 | 40 | [9] | 40 | [9] | 8 | [6] | 7 | [6] | 8 | 1 | 1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 171 | ' | 170 | ' | ' | ' | ' | 0 | 82 | 75 | 49 | 43 | 0 | 6 | 0 | 6 | 0 | 0 | 40 | [9] | 40 | [9] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 111 | ' | 169 | ' | 0 | 0 | 36 | 88 | 20 | 20 | 0 | 39 | [10] | 48 | [10] | 7 | 3 | 2 | 8 | 8 | 0 | 1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 31 | ' | 29 | 0 | 21 | 22 | 0 | 0 | 0 | 2 | [8] | 0 | 0 | 0 | 0 | 8 | [6] | 7 | [6] | 8 | 8 | 7 | 0 | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8 | ' | ||||||||||||||||||||||||
Noncurrent regulatory liabilities | $4,204 | ' | $3,981 | $2,593 | $2,397 | $1,420 | $1,406 | ' | $0 | $119 | $132 | $0 | $7 | $0 | ' | $0 | $0 | ' | ' | ' | ' | $46 | $1 | $10 | $14 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $0 | ' | ' | $3,393 | ' | $3,229 | ' | ' | ' | $2,184 | $2,037 | $1,202 | $1,192 | $0 | $0 | $0 | $0 | $7 | $0 | $0 | $0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $592 | ' | $538 | $409 | $360 | $0 | ' | $0 | $119 | $132 | $0 | ' | $0 | ' | $0 | $0 | $40 | $46 | ' | $10 | $14 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $218 | ' | $214 | $0 | $218 | $214 | $0 | $0 | $0 | ' | $0 | ' | $0 | $0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $40 | ' | |||||||||||||||||||||||||||||||||||
[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. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[3] | Represents the regulatory asset recorded at Exelon Corporate for the difference in the fair value of the long-term debt of BGE as of the merger date. The asset is amortized over the life of the underlying debt. See Note 11 b Debt and Credit Agreements for additional information. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[4] | Represents the regulatory asset recorded at Exelon Corporate representing the fair value of BGE's supply contracts as of the close of the merger date. BGE is allowed full recovery of the costs of its electric and gas supply contracts through approved, regulated rates. The asset is amortized over a period of approximately 3 years. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[5] | ReIates to integration costs to achieve distribution synergies related to the merger transaction. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[6] | Represents the electric and gas distribution costs recoverable from or refundable to customers under BGEbs decoupling mechanism. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[7] | Relates to under-recovered transmission costs. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[8] | Relates to $2 million of over-recovered natural electric supply costs as of September 30, 2013. As of December 31, 2012, includes $9 million of under-recovered electric supply costs and $19 million of under-recovered natural gas supply costs. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[9] | Primarily represents the regulatory liability for revenue subject to refund recorded pursuant to the ICCbs order in the 2007 Rate Case. See above for discussion regarding the 2007 Rate Case. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[10] | Includes $18 million related to the DSP program, $13 million related to the over-recovered natural gas costs under the PGC and $8 million related to over-recovered electric transmission costs as of September 30, 2013. As of December 31, 2012, includes $47 million related to the over-recovered electric supply costs under the GSA and $1 million related to the over-recovered natural gas costs under the PGC. |
Merger_and_Acquisitions_Detail
Merger and Acquisitions (Details) (USD $) | 3 Months Ended | 9 Months Ended | |||||||
Sep. 30, 2013 | Mar. 31, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | |||||
Finite Lived Intangible Assets Net [Abstract] | ' | ' | ' | ' | ' | ||||
Amortization of Regulatory Asset | $19,000,000 | ' | $36,000,000 | $57,000,000 | $80,000,000 | ||||
Payments To Acquire Businesses Net Of Cash Acquired [Abstract] | ' | ' | ' | ' | ' | ||||
Payments To Acquire Businesses Gross | ' | ' | ' | ' | 0 | ||||
Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Net Abstract | ' | ' | ' | ' | ' | ||||
Total assets | 22,900,000,000 | ' | ' | 22,900,000,000 | ' | ||||
Business Acquisition, Impact Of Merger [Abstract] | ' | ' | ' | ' | ' | ||||
Revenues | 6,502,000,000 | [1] | ' | 6,579,000,000 | [1] | 18,725,000,000 | [2] | 17,235,000,000 | [2] |
Net income | 736,000,000 | ' | 297,000,000 | 1,235,000,000 | 787,000,000 | ||||
Business Acquisition, Pro Forma Information [Abstract] | ' | ' | ' | ' | ' | ||||
Business Acquisition, Pro Forma Earnings Per Share, Basic | ' | ' | ' | ' | $1.79 | ||||
Business Acquisition, Pro Forma Earnings Per Share, Diluted | ' | ' | ' | ' | $1.79 | ||||
Business Acquisition, Regulatory Matters [Abstract] | ' | ' | ' | ' | ' | ||||
Business Acquisition, Construction Time Frame | ' | ' | ' | '2 years | ' | ||||
Business Acquisition, Gain (Loss) On Assets Sold | 272,000,000 | ' | ' | 272,000,000 | ' | ||||
Business Acquisition, Gain (Loss) On Assets Sold Update | ' | ' | ' | 8,000,000 | ' | ||||
Business Acquisition Potential Cash Payment | 40,000,000 | ' | ' | 40,000,000 | ' | ||||
Restructuring Reserve [Roll Forward] | ' | ' | ' | ' | ' | ||||
Restructuring Reserve, Period Start | ' | 111,000,000 | ' | 111,000,000 | ' | ||||
Severance Charges | 3,000,000 | ' | 8,000,000 | 6,000,000 | 117,000,000 | ||||
Non-Merger Severance Costs | ' | ' | ' | ' | 120,000,000 | ||||
Stock Compensation Expense | ' | ' | 3,000,000 | ' | 6,000,000 | ||||
Other Expense Charges | ' | ' | ' | ' | 7,000,000 | ||||
Total Severance Benefits | ' | ' | 11,000,000 | [3] | ' | 130,000,000 | [3] | ||
Payments | ' | ' | ' | 52,000,000 | ' | ||||
Restructuring Reserve, Period End | 65,000,000 | ' | ' | 65,000,000 | ' | ||||
Severance [Member] | ' | ' | ' | ' | ' | ||||
Restructuring Reserve [Roll Forward] | ' | ' | ' | ' | ' | ||||
Restructuring Reserve, Intercompany Allocation | ' | ' | ' | 5,000,000 | [4] | ' | |||
Stock Compensation Plan [Member] | ' | ' | ' | ' | ' | ||||
Restructuring Reserve [Roll Forward] | ' | ' | ' | ' | ' | ||||
Restructuring Reserve, Intercompany Allocation | ' | ' | ' | 1,000,000 | ' | ||||
Other Severance Charges [Member] | ' | ' | ' | ' | ' | ||||
Restructuring Reserve [Roll Forward] | ' | ' | ' | ' | ' | ||||
Severance Charges | 12,000,000 | ' | 5,000,000 | 14,000,000 | 11,000,000 | ||||
Minimum [Member] | ' | ' | ' | ' | ' | ||||
Business Acquisition, Regulatory Matters [Abstract] | ' | ' | ' | ' | ' | ||||
Business Acquisition, Construction Cost | 95,000,000 | ' | ' | 95,000,000 | ' | ||||
Maximum [Member] | ' | ' | ' | ' | ' | ||||
Business Acquisition, Regulatory Matters [Abstract] | ' | ' | ' | ' | ' | ||||
Business Acquisition, Construction Cost | 120,000,000 | ' | ' | 120,000,000 | ' | ||||
Constellation Energy Group Acquisition [Member] | ' | ' | ' | ' | ' | ||||
Payments to Acquire Businesses and Interest in Affiliates [Abstract] | ' | ' | ' | ' | ' | ||||
Business Combination, Integration Related Costs | 43,000,000 | ' | 95,000,000 | 106,000,000 | 729,000,000 | ||||
Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Net Abstract | ' | ' | ' | ' | ' | ||||
Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Property Plant And Equipment | 9,342,000,000 | ' | ' | 9,342,000,000 | ' | ||||
Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Asset Retirment Obligations | 740,000,000 | ' | ' | 740,000,000 | ' | ||||
Current Assets | 4,936,000,000 | ' | ' | 4,936,000,000 | ' | ||||
Unamortized Energy Contracts | 3,218,000,000 | ' | ' | 3,218,000,000 | ' | ||||
Other intangibles, trade name and retail relationships | 457,000,000 | ' | ' | 457,000,000 | ' | ||||
Investment in affiliates | 1,942,000,000 | ' | ' | 1,942,000,000 | ' | ||||
Other assets | 2,265,000,000 | ' | ' | 2,265,000,000 | ' | ||||
BusinessCombinationRecognizedIdentifiableAssetsAcquiredAndLiabilitiesAssumedLiabilitiesAbstract | ' | ' | ' | ' | ' | ||||
Current liabilities | 3,408,000,000 | ' | ' | 3,408,000,000 | ' | ||||
Unamortized energy contracts | 1,722,000,000 | ' | ' | 1,722,000,000 | ' | ||||
Long-term debt, including current maturities | 5,632,000,000 | ' | ' | 5,632,000,000 | ' | ||||
Business Combination Aquisition Of Less than 100 Percent Noncontrolling Interest Fair Value | 90,000,000 | ' | ' | 90,000,000 | ' | ||||
Deferred credits and other liabilities and preferred securities | 4,683,000,000 | ' | ' | 4,683,000,000 | ' | ||||
Total liabilities,preferred securities and noncontrolling Interest | 15,535,000,000 | ' | ' | 15,535,000,000 | ' | ||||
Total purchase price | 7,365,000,000 | ' | ' | 7,365,000,000 | ' | ||||
Business Acquisition, Impact Of Merger [Abstract] | ' | ' | ' | ' | ' | ||||
Regulatory Assets Transfer Changes | ' | ' | ' | 15,000,000 | 49,000,000 | ||||
Business Acquisition, Pro Forma Information [Abstract] | ' | ' | ' | ' | ' | ||||
Business Acquisition, Pro Forma Revenue | ' | ' | 6,841,000,000 | ' | 20,084,000,000 | ||||
Business Acquisition, Pro Forma Net Income (Loss) | ' | ' | 492,000,000 | ' | 1,439,000,000 | ||||
Business Acquisition, Pro Forma Earnings Per Share, Basic | ' | ' | $0.58 | ' | ' | ||||
Business Acquisition, Pro Forma Earnings Per Share, Diluted | ' | ' | $0.57 | ' | ' | ||||
Business Acquisition, Regulatory Matters [Abstract] | ' | ' | ' | ' | ' | ||||
Business Acquisition, Direct Investment With State And Local Governments Due To Settlement | 1,000,000,000 | ' | ' | 1,000,000,000 | ' | ||||
Business Acquisition, Development Of New Generation Cost | 625,000,000 | ' | ' | 625,000,000 | ' | ||||
Business Acquisition, Expected New Generation Development Time Frame | ' | ' | ' | '10 years | ' | ||||
Constellation Energy Group Acquisition [Member] | Minimum [Member] | ' | ' | ' | ' | ' | ||||
Business Acquisition, Regulatory Matters [Abstract] | ' | ' | ' | ' | ' | ||||
Business Acquisition, Expected New Generation Mwh | ' | ' | ' | 285 | ' | ||||
Constellation Energy Group Acquisition [Member] | Maximum [Member] | ' | ' | ' | ' | ' | ||||
Business Acquisition, Regulatory Matters [Abstract] | ' | ' | ' | ' | ' | ||||
Business Acquisition, Expected New Generation Mwh | ' | ' | ' | 300 | ' | ||||
Exelon Generation Co L L C [Member] | ' | ' | ' | ' | ' | ||||
Payments To Acquire Businesses Net Of Cash Acquired [Abstract] | ' | ' | ' | ' | ' | ||||
Payments To Acquire Businesses Gross | ' | ' | ' | ' | 0 | ||||
Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Net Abstract | ' | ' | ' | ' | ' | ||||
DOE loan guarantee | ' | ' | ' | 646,000,000 | ' | ||||
Total assets | 14,575,000,000 | ' | ' | 14,575,000,000 | ' | ||||
Business Acquisition, Impact Of Merger [Abstract] | ' | ' | ' | ' | ' | ||||
Revenues | 4,255,000,000 | ' | 4,031,000,000 | 11,858,000,000 | 10,539,000,000 | ||||
Net income | 485,000,000 | ' | 87,000,000 | 795,000,000 | 419,000,000 | ||||
Business Acquisition, Regulatory Matters [Abstract] | ' | ' | ' | ' | ' | ||||
Lease Agreement Time Frame | ' | ' | ' | '20 years | ' | ||||
Restructuring Reserve [Roll Forward] | ' | ' | ' | ' | ' | ||||
Restructuring Reserve, Period Start | ' | 33,000,000 | ' | 33,000,000 | ' | ||||
Severance Charges | 3,000,000 | ' | 4,000,000 | 6,000,000 | 68,000,000 | ||||
Non-Merger Severance Costs | ' | ' | ' | ' | 34,000,000 | ||||
Stock Compensation Expense | ' | ' | 2,000,000 | ' | 4,000,000 | ||||
Other Expense Charges | ' | ' | ' | ' | 4,000,000 | ||||
Total Severance Benefits | ' | ' | 6,000,000 | [3] | ' | 76,000,000 | [3] | ||
Payments | ' | ' | ' | 20,000,000 | ' | ||||
Restructuring Reserve, Intercompany Allocation | 2,000,000 | ' | 0 | 3,000,000 | 40,000,000 | ||||
Restructuring Reserve, Period End | 14,000,000 | ' | ' | 14,000,000 | ' | ||||
Exelon Generation Co L L C [Member] | Severance [Member] | ' | ' | ' | ' | ' | ||||
Restructuring Reserve [Roll Forward] | ' | ' | ' | ' | ' | ||||
Severance Charges | ' | ' | ' | 1,000,000 | [4] | ' | |||
Exelon Generation Co L L C [Member] | Other Severance Charges [Member] | ' | ' | ' | ' | ' | ||||
Restructuring Reserve [Roll Forward] | ' | ' | ' | ' | ' | ||||
Severance Charges | 11,000,000 | ' | 3,000,000 | 12,000,000 | 8,000,000 | ||||
Exelon Generation Co L L C [Member] | Constellation Energy Group Acquisition [Member] | ' | ' | ' | ' | ' | ||||
Payments to Acquire Businesses and Interest in Affiliates [Abstract] | ' | ' | ' | ' | ' | ||||
Business Combination, Integration Related Costs | 32,000,000 | ' | 79,000,000 | 75,000,000 | 283,000,000 | ||||
Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Net Abstract | ' | ' | ' | ' | ' | ||||
Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Property Plant And Equipment | 4,054,000,000 | ' | ' | 4,054,000,000 | ' | ||||
Current Assets | 3,638,000,000 | ' | ' | 3,638,000,000 | ' | ||||
Unamortized Energy Contracts | 3,218,000,000 | ' | ' | 3,218,000,000 | ' | ||||
Other intangibles, trade name and retail relationships | 457,000,000 | ' | ' | 457,000,000 | ' | ||||
Investment in affiliates | 1,942,000,000 | ' | ' | 1,942,000,000 | ' | ||||
Other assets | 1,266,000,000 | ' | ' | 1,266,000,000 | ' | ||||
BusinessCombinationRecognizedIdentifiableAssetsAcquiredAndLiabilitiesAssumedLiabilitiesAbstract | ' | ' | ' | ' | ' | ||||
Current liabilities | 2,804,000,000 | ' | ' | 2,804,000,000 | ' | ||||
Unamortized energy contracts | 1,512,000,000 | ' | ' | 1,512,000,000 | ' | ||||
Long-term debt, including current maturities | 2,972,000,000 | ' | ' | 2,972,000,000 | ' | ||||
Business Combination Aquisition Of Less than 100 Percent Noncontrolling Interest Fair Value | 90,000,000 | ' | ' | 90,000,000 | ' | ||||
Deferred credits and other liabilities and preferred securities | 1,933,000,000 | ' | ' | 1,933,000,000 | ' | ||||
Total liabilities,preferred securities and noncontrolling Interest | 9,311,000,000 | ' | ' | 9,311,000,000 | ' | ||||
Total purchase price | 5,264,000,000 | ' | ' | 5,264,000,000 | ' | ||||
Business Acquisition, Pro Forma Information [Abstract] | ' | ' | ' | ' | ' | ||||
Business Acquisition, Pro Forma Revenue | ' | ' | 4,293,000,000 | ' | 12,753,000,000 | ||||
Business Acquisition, Pro Forma Net Income (Loss) | ' | ' | 282,000,000 | ' | 805,000,000 | ||||
Exelon Generation Co L L C [Member] | Perryman Construction [Member] | ' | ' | ' | ' | ' | ||||
Business Acquisition, Regulatory Matters [Abstract] | ' | ' | ' | ' | ' | ||||
Business Acquisition, Construction Cost | 80,000,000 | ' | ' | 80,000,000 | ' | ||||
Business Acquisition, Divesture Wattage | ' | ' | ' | 120 | ' | ||||
Commonwealth Edison Co [Member] | ' | ' | ' | ' | ' | ||||
Business Acquisition, Impact Of Merger [Abstract] | ' | ' | ' | ' | ' | ||||
Revenues | 1,156,000,000 | ' | 1,484,000,000 | 3,395,000,000 | 4,154,000,000 | ||||
Net income | 126,000,000 | ' | 90,000,000 | 140,000,000 | 219,000,000 | ||||
Restructuring Reserve [Roll Forward] | ' | ' | ' | ' | ' | ||||
Restructuring Reserve, Period Start | ' | 1,000,000 | ' | 1,000,000 | ' | ||||
Severance Charges | ' | ' | 1,000,000 | [5] | ' | 16,000,000 | [5] | ||
Stock Compensation Expense | ' | ' | 1,000,000 | [5] | ' | 1,000,000 | [5] | ||
Other Expense Charges | ' | ' | ' | ' | 1,000,000 | [5] | |||
Total Severance Benefits | ' | ' | 2,000,000 | [3],[5] | ' | 18,000,000 | [3],[5] | ||
Restructuring Reserve, Intercompany Allocation | ' | ' | 2,000,000 | ' | 16,000,000 | ||||
Restructuring Reserve, Period End | 1,000,000 | ' | ' | 1,000,000 | ' | ||||
Merger related severance regulatory asset | ' | ' | 2,000,000 | ' | 18,000,000 | ||||
Commonwealth Edison Co [Member] | Other Severance Charges [Member] | ' | ' | ' | ' | ' | ||||
Restructuring Reserve [Roll Forward] | ' | ' | ' | ' | ' | ||||
Severance Charges | 1,000,000 | ' | 1,000,000 | 2,000,000 | 1,000,000 | ||||
Commonwealth Edison Co [Member] | Constellation Energy Group Acquisition [Member] | ' | ' | ' | ' | ' | ||||
Payments to Acquire Businesses and Interest in Affiliates [Abstract] | ' | ' | ' | ' | ' | ||||
Business Combination, Integration Related Costs | 5,000,000 | ' | 8,000,000 | 14,000,000 | 34,000,000 | ||||
Business Acquisition, Impact Of Merger [Abstract] | ' | ' | ' | ' | ' | ||||
Regulatory Assets Transfer Changes | ' | ' | ' | 10,000,000 | 30,000,000 | ||||
PECO Energy Co [Member] | ' | ' | ' | ' | ' | ||||
Business Acquisition, Impact Of Merger [Abstract] | ' | ' | ' | ' | ' | ||||
Revenues | 728,000,000 | ' | 806,000,000 | 2,295,000,000 | 2,396,000,000 | ||||
Net income | 92,000,000 | ' | 123,000,000 | 292,000,000 | 300,000,000 | ||||
Restructuring Reserve [Roll Forward] | ' | ' | ' | ' | ' | ||||
Severance Charges | ' | ' | 1,000,000 | ' | 8,000,000 | ||||
Non-Merger Severance Costs | ' | ' | ' | ' | 1,000,000 | ||||
Total Severance Benefits | ' | ' | 1,000,000 | [3] | ' | 8,000,000 | [3] | ||
Restructuring Reserve, Intercompany Allocation | ' | ' | 1,000,000 | ' | 8,000,000 | ||||
PECO Energy Co [Member] | Constellation Energy Group Acquisition [Member] | ' | ' | ' | ' | ' | ||||
Payments to Acquire Businesses and Interest in Affiliates [Abstract] | ' | ' | ' | ' | ' | ||||
Business Combination, Integration Related Costs | 3,000,000 | ' | 3,000,000 | 8,000,000 | 13,000,000 | ||||
Baltimore Gas and Electric Company [Member] | ' | ' | ' | ' | ' | ||||
Business Acquisition, Impact Of Merger [Abstract] | ' | ' | ' | ' | ' | ||||
Revenues | 737,000,000 | ' | 720,000,000 | 2,271,000,000 | 2,032,000,000 | ||||
Revenues Impact | ' | ' | 720,000,000 | ' | 1,388,000,000 | ||||
Net Income Loss Impact | ' | ' | 0 | ' | -49,000,000 | ||||
Net income | 53,000,000 | ' | 0 | 160,000,000 | -14,000,000 | ||||
Regulatory Assets Transfer Changes | ' | 6,000,000 | ' | 8,000,000 | ' | ||||
Restructuring Reserve [Roll Forward] | ' | ' | ' | ' | ' | ||||
Restructuring Reserve, Period Start | ' | 11,000,000 | ' | 11,000,000 | ' | ||||
Severance Charges | ' | ' | 1,000,000 | [6] | ' | 18,000,000 | [6] | ||
Other Expense Charges | ' | ' | ' | ' | 1,000,000 | [6] | |||
Total Severance Benefits | ' | ' | 1,000,000 | [3],[6] | ' | 19,000,000 | [3],[6] | ||
Payments | ' | ' | ' | 4,000,000 | ' | ||||
Restructuring Reserve, Intercompany Allocation | ' | ' | 1,000,000 | ' | 7,000,000 | ||||
Restructuring Reserve, Period End | 7,000,000 | ' | ' | 7,000,000 | ' | ||||
Merger related severance regulatory asset | ' | ' | 1,000,000 | ' | 19,000,000 | ||||
Baltimore Gas and Electric Company [Member] | Other Severance Charges [Member] | ' | ' | ' | ' | ' | ||||
Restructuring Reserve [Roll Forward] | ' | ' | ' | ' | ' | ||||
Severance Charges | ' | ' | 1,000,000 | ' | 2,000,000 | ||||
Baltimore Gas and Electric Company [Member] | Constellation Energy Group Acquisition [Member] | ' | ' | ' | ' | ' | ||||
Payments to Acquire Businesses and Interest in Affiliates [Abstract] | ' | ' | ' | ' | ' | ||||
Business Combination, Integration Related Costs | 2,000,000 | ' | 1,000,000 | 5,000,000 | 172,000,000 | ||||
Business Acquisition, Impact Of Merger [Abstract] | ' | ' | ' | ' | ' | ||||
Regulatory Assets Transfer Changes | ' | ' | ' | 5,000,000 | 19,000,000 | ||||
Constellation Energy Group Acquisition [Member] | Total Assets [Member] | ' | ' | ' | ' | ' | ||||
Acquired Finite-Lived Intangible Assets [Line Items] | ' | ' | ' | ' | ' | ||||
Finite-lived Intangible Assets Acquired | ' | ' | ' | 586,000,000 | ' | ||||
Finite Lived Intangible Assets Net [Abstract] | ' | ' | ' | ' | ' | ||||
Finite lived intangible assets gross | 1,956,000,000 | ' | ' | 1,956,000,000 | ' | ||||
Finite lived intangible assets accumulated amortization | -1,370,000,000 | ' | ' | -1,370,000,000 | ' | ||||
Finite Lived Intangible Assets Future Amortization Expense [Abstract] | ' | ' | ' | ' | ' | ||||
Future amortization expense within the next twelve months | 90,000,000 | ' | ' | 90,000,000 | ' | ||||
Future amortization expense in year two | 118,000,000 | ' | ' | 118,000,000 | ' | ||||
Future amortizationExpense in year three | 60,000,000 | ' | ' | 60,000,000 | ' | ||||
Future amortization expense in year four | 11,000,000 | ' | ' | 11,000,000 | ' | ||||
Future amortization expense in year five | 21,000,000 | ' | ' | 21,000,000 | ' | ||||
Future amortization expense in year six and thereafter | ' | ' | ' | 286,000,000 | ' | ||||
Customer Relationships [Member] | ' | ' | ' | ' | ' | ||||
Finite Lived Intangible Assets Net [Abstract] | ' | ' | ' | ' | ' | ||||
Amortization Of Contracts | 8,000,000 | ' | 2,000,000 | 17,000,000 | 9,000,000 | ||||
Customer Relationships [Member] | Constellation Energy Group Acquisition [Member] | ' | ' | ' | ' | ' | ||||
Acquired Finite-Lived Intangible Assets [Line Items] | ' | ' | ' | ' | ' | ||||
Acquired Finite Lived Intangible Asset Weighted Average Useful Life | ' | ' | ' | '12 years 4 months 26 days | ' | ||||
Customer Relationships [Member] | Constellation Energy Group Acquisition [Member] | Total Assets [Member] | ' | ' | ' | ' | ' | ||||
Acquired Finite-Lived Intangible Assets [Line Items] | ' | ' | ' | ' | ' | ||||
Finite-lived Intangible Assets Acquired | ' | ' | ' | 183,000,000 | ' | ||||
Finite Lived Intangible Assets Net [Abstract] | ' | ' | ' | ' | ' | ||||
Finite lived intangible assets gross | 214,000,000 | ' | ' | 214,000,000 | ' | ||||
Finite lived intangible assets accumulated amortization | -31,000,000 | ' | ' | -31,000,000 | ' | ||||
Finite Lived Intangible Assets Future Amortization Expense [Abstract] | ' | ' | ' | ' | ' | ||||
Future amortization expense within the next twelve months | 5,000,000 | ' | ' | 5,000,000 | ' | ||||
Future amortization expense in year two | 19,000,000 | ' | ' | 19,000,000 | ' | ||||
Future amortizationExpense in year three | 18,000,000 | ' | ' | 18,000,000 | ' | ||||
Future amortization expense in year four | 18,000,000 | ' | ' | 18,000,000 | ' | ||||
Future amortization expense in year five | 18,000,000 | ' | ' | 18,000,000 | ' | ||||
Future amortization expense in year six and thereafter | ' | ' | ' | 105,000,000 | ' | ||||
Trade Names [Member] | ' | ' | ' | ' | ' | ||||
Finite Lived Intangible Assets Net [Abstract] | ' | ' | ' | ' | ' | ||||
Amortization Of Contracts | 8,000,000 | ' | 6,000,000 | 20,000,000 | 14,000,000 | ||||
Trade Names [Member] | Constellation Energy Group Acquisition [Member] | ' | ' | ' | ' | ' | ||||
Acquired Finite-Lived Intangible Assets [Line Items] | ' | ' | ' | ' | ' | ||||
Acquired Finite Lived Intangible Asset Weighted Average Useful Life | ' | ' | ' | '10 years | ' | ||||
Trade Names [Member] | Constellation Energy Group Acquisition [Member] | Total Assets [Member] | ' | ' | ' | ' | ' | ||||
Acquired Finite-Lived Intangible Assets [Line Items] | ' | ' | ' | ' | ' | ||||
Finite-lived Intangible Assets Acquired | ' | ' | ' | 203,000,000 | ' | ||||
Finite Lived Intangible Assets Net [Abstract] | ' | ' | ' | ' | ' | ||||
Finite lived intangible assets gross | 243,000,000 | ' | ' | 243,000,000 | ' | ||||
Finite lived intangible assets accumulated amortization | -40,000,000 | ' | ' | -40,000,000 | ' | ||||
Finite Lived Intangible Assets Future Amortization Expense [Abstract] | ' | ' | ' | ' | ' | ||||
Future amortization expense within the next twelve months | 6,000,000 | ' | ' | 6,000,000 | ' | ||||
Future amortization expense in year two | 24,000,000 | ' | ' | 24,000,000 | ' | ||||
Future amortizationExpense in year three | 24,000,000 | ' | ' | 24,000,000 | ' | ||||
Future amortization expense in year four | 24,000,000 | ' | ' | 24,000,000 | ' | ||||
Future amortization expense in year five | 24,000,000 | ' | ' | 24,000,000 | ' | ||||
Future amortization expense in year six and thereafter | ' | ' | ' | 101,000,000 | ' | ||||
Power Supply Contracts [Member] | ' | ' | ' | ' | ' | ||||
Finite Lived Intangible Assets Net [Abstract] | ' | ' | ' | ' | ' | ||||
Finite lived intangible assets net | 32,000,000 | ' | ' | 32,000,000 | ' | ||||
Amortization Of Contracts | 40,000,000 | ' | 261,000,000 | 372,000,000 | 794,000,000 | ||||
Power Supply Contracts [Member] | Constellation Energy Group Acquisition [Member] | ' | ' | ' | ' | ' | ||||
Acquired Finite-Lived Intangible Assets [Line Items] | ' | ' | ' | ' | ' | ||||
Acquired Finite Lived Intangible Asset Weighted Average Useful Life | ' | ' | ' | '1 year 6 months 3 days | ' | ||||
Power Supply Contracts [Member] | Constellation Energy Group Acquisition [Member] | Total Assets [Member] | ' | ' | ' | ' | ' | ||||
Acquired Finite-Lived Intangible Assets [Line Items] | ' | ' | ' | ' | ' | ||||
Finite-lived Intangible Assets Acquired | ' | ' | ' | 200,000,000 | ' | ||||
Finite Lived Intangible Assets Net [Abstract] | ' | ' | ' | ' | ' | ||||
Finite lived intangible assets gross | 1,499,000,000 | [7] | ' | ' | 1,499,000,000 | [7] | ' | ||
Finite lived intangible assets accumulated amortization | -1,299,000,000 | [7] | ' | ' | -1,299,000,000 | [7] | ' | ||
Finite Lived Intangible Assets Future Amortization Expense [Abstract] | ' | ' | ' | ' | ' | ||||
Future amortization expense within the next twelve months | 79,000,000 | [7] | ' | ' | 79,000,000 | [7] | ' | ||
Future amortization expense in year two | 75,000,000 | [7] | ' | ' | 75,000,000 | [7] | ' | ||
Future amortizationExpense in year three | 18,000,000 | [7] | ' | ' | 18,000,000 | [7] | ' | ||
Future amortization expense in year four | -31,000,000 | [7] | ' | ' | -31,000,000 | [7] | ' | ||
Future amortization expense in year five | -21,000,000 | [7] | ' | ' | -21,000,000 | [7] | ' | ||
Future amortization expense in year six and thereafter | ' | ' | ' | $80,000,000 | [7] | ' | |||
[1] | For the three months ended September 30, 2013 and 2012, utility taxes of $21 million and $28 million, respectively, are included in revenues and expenses for Generation. For the three months ended September 30, 2013 and 2012, utility taxes of $65 million and $67 million, respectively, are included in revenues and expenses for ComEd. For the three months ended September 30, 2013 and 2012, utility taxes of $33 million and $40 million, respectively, are included in revenues and expenses for PECO. For the three months ended September 30, 2013 and 2012, utility taxes of $20 million and $20 million, respectively, are included in revenues and expenses for BGE. | ||||||||
[2] | For the nine months ended September 30, 2013 and 2012, utility taxes of $60 million and $60 million, respectively, are included in revenues and expenses for Generation. For the nine months ended September 30, 2013 and 2012, utility taxes of $182 million and $182 million, respectively, are included in revenues and expenses for ComEd. For the nine months ended September 30, 2013 and 2012, utility taxes of $97 million and $108 million, respectively, are included in revenues and expenses for PECO. For the nine months ended September 30, 2013 and period of March 12, 2012 through September 30, 2012, utility taxes of $62 million and $42 million, respectively, are included in revenues and expenses for BGE. | ||||||||
[3] | The amounts above include $0 million and $40 million at Generation, $2 million and $16 million at ComEd, $1 million and $8 million at PECO, and $1 million and $7 million at BGE, for amounts billed by BSC through intercompany allocations for the three and nine months ended September 30, 2012, respectively. | ||||||||
[4] | Includes salary continuance and health and welfare severance benefits. Amounts represent ongoing severance plan benefits. | ||||||||
[5] | ComEd established regulatory assets of $2 million and $18 million for severance benefits costs for the three and nine months ended September 30, 2012, respectively. The majority of these costs are expected to be recovered over a five-year period. | ||||||||
[6] | BGE established regulatory assets of $1 million and $19 million for severance benefits costs for the three and nine months ended September 30, 2012, respectively. The majority of these costs are being recovered over a five-year period beginning in March 2013. (d) Primarily includes life insurance, employer payroll taxes, educational assistance and outplacement services. | ||||||||
[7] | Includes the fair value of BGE's power and gas supply contracts of $32 million for which an offsetting regulatory asset was also recorded |
Investment_in_Constellation_En2
Investment in Constellation Energy Nuclear Group, LLC (Details) (USD $) | 9 Months Ended | 3 Months Ended | 7 Months Ended | 9 Months Ended | 3 Months Ended | 7 Months Ended | 9 Months Ended | 3 Months Ended | 7 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 7 Months Ended | 9 Months Ended | 3 Months Ended | 7 Months Ended | 9 Months Ended | 3 Months Ended | 7 Months Ended | 9 Months Ended | 3 Months Ended | |||||||||||||||||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Jun. 30, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Jun. 30, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Jun. 30, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Jun. 30, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Jun. 30, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Jun. 30, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | ||||
Power Purchase Agreement [Member] | Power Purchase Agreement [Member] | Power Purchase Agreement [Member] | Power Purchase Agreement [Member] | Power Service Agency Agreement [Member] | Power Service Agency Agreement [Member] | Power Service Agency Agreement [Member] | Power Service Agency Agreement [Member] | Administrative Services Agreement [Member] | Administrative Services Agreement [Member] | Administrative Services Agreement [Member] | Administrative Services Agreement [Member] | CENG [Member] | CENG [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | |||||||
Minimum [Member] | Power Purchase Agreement [Member] | Power Purchase Agreement [Member] | Power Purchase Agreement [Member] | Power Purchase Agreement [Member] | Power Service Agency Agreement [Member] | Power Service Agency Agreement [Member] | Power Service Agency Agreement [Member] | Power Service Agency Agreement [Member] | Administrative Services Agreement [Member] | Administrative Services Agreement [Member] | Administrative Services Agreement [Member] | Administrative Services Agreement [Member] | CENG [Member] | CENG [Member] | |||||||||||||||||||||||||
Schedule of Equity Method Investments [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Percentage of ownership interest in CENG (as a percent) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50.01% | ' | 50.01% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
CENG | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $93 | $53 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $68 | $58 | ||||
Amortization of basis difference in CENG | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -88 | -131 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -31 | -57 | ||||
Total equity investment earnings (losses) - CENG | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5 | -78 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 37 | 1 | ||||
Basis difference in investment in CENG | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 204 | ' | 204 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Related Party Transaction [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Required purchases of power from CENG's nuclear plants not sold to third parties (as a percent) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 85.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Purchase of nuclear output by EDF (as a percent) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 49.99% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Impact Of Transactions Under Agreements [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Increase (Decrease) in earnings | ' | ' | -269 | -282 | -541 | -748 | 1 | 1 | 2 | 3 | 10 | 14 | 30 | 32 | ' | ' | 384 | 473 | 1,129 | 1,263 | ' | -269 | -282 | -541 | -748 | 1 | 1 | 2 | 3 | 10 | 14 | 30 | 32 | ' | ' | ||||
Amount receivable from (payable to) related to agreements with CENG | ' | ' | -76 | ' | -86 | -76 | ' | ' | ' | ' | 4 | ' | 5 | 4 | ' | ' | ' | ' | ' | ' | ' | -76 | ' | -86 | -76 | ' | ' | ' | ' | 4 | ' | 5 | 4 | ' | ' | ||||
Amortization of energy contract assets and liabilities | 342 | [1] | 731 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 398 | [1] | 812 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Loan to CENG/Distribution to EDF/ Repayment to Generation | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $400 | ' | $400 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Interest rate on loan to CENG | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5.25% | ' | 5.25% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Return on distributions (CENG) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8.50% | ' | 8.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
[1] | Included in purchased power and fuel expense on the Registrants' Consolidated Statements of Operations and Comprehensive Income |
Recovered_Sheet2
Impairment of Long-Lived Assets (Details) (USD $) | 3 Months Ended | 9 Months Ended | |
Sep. 30, 2013 | Jun. 30, 2013 | Sep. 30, 2013 | |
Capital Leases, Net Investment in Direct Financing Leases [Abstract] | ' | ' | ' |
Capital Leases, Net Investment in Direct Financing Leases, Unguaranteed Residual Values of Leased Property | $1,600,000,000 | ' | $1,600,000,000 |
Tangible Asset Impairment Charges | ' | ' | 14,000,000 |
CapitalLeaseNetInvestmentInDirectFinancingLeasesPrepaymentsReceived | 1,200,000,000 | ' | 1,200,000,000 |
Utilities Operating Expense Maintenance And Operations [Abstract] | ' | ' | ' |
Utilities Operating Expense, Impairments | 92,000,000 | 21,000,000 | ' |
Interest Costs Incurred [Abstract] | ' | ' | ' |
Interest Costs Incurred | 8,000,000 | ' | ' |
Exelon Generation Co L L C [Member] | ' | ' | ' |
Utilities Operating Expense Maintenance And Operations [Abstract] | ' | ' | ' |
Utilities Operating Expense, Impairments | 92,000,000 | 21,000,000 | ' |
Interest Costs Incurred [Abstract] | ' | ' | ' |
Interest Costs Incurred | $8,000,000 | ' | ' |
Goodwill_Details
Goodwill (Details) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 |
In Millions, unless otherwise specified | Commonwealth Edison Co [Member] | ||
Goodwill, Impaired [Abstract] | ' | ' | ' |
Percentage decrease in fair value | ' | ' | 10.00% |
Goodwill [Roll Forward] | ' | ' | ' |
Goodwill, beginning balance | $2,625 | $2,625 | $2,625 |
Goodwill, ending balance | $2,625 | $2,625 | $2,625 |
Accounts_Receivable_Details
Accounts Receivable (Details) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
In Millions, unless otherwise specified | ||
Accounts Notes And Loans Receivable Net Current [Abstract] | ' | ' |
Allowance for uncollectible accounts | $302 | $293 |
Accounts Receivable Additional Disclosures [Abstract] | ' | ' |
Gross Accounts Receivable Pledged as Collateral | 0 | 289 |
Exelon Generation Co L L C [Member] | ' | ' |
Accounts Notes And Loans Receivable Net Current [Abstract] | ' | ' |
Allowance for uncollectible accounts | 72 | 84 |
Commonwealth Edison Co [Member] | ' | ' |
Accounts Notes And Loans Receivable Net Current [Abstract] | ' | ' |
Allowance for uncollectible accounts | 73 | 70 |
PECO Energy Co [Member] | ' | ' |
Accounts Notes And Loans Receivable Net Current [Abstract] | ' | ' |
Allowance for uncollectible accounts | 119 | 99 |
Accounts Receivable Additional Disclosures [Abstract] | ' | ' |
Gross Accounts Receivable Pledged as Collateral | ' | 289 |
Financing Receivable Recorded Investment [Line Items] | ' | ' |
Installment plan receivables | 22 | 18 |
Installment plan receivables uncollectible accounts reserve | -22 | -15 |
PECO Energy Co [Member] | Low To Medium Risk [Member] | ' | ' |
Financing Receivable Recorded Investment [Line Items] | ' | ' |
Installment plan receivables uncollectible accounts reserve | -1 | -1 |
PECO Energy Co [Member] | Medium Risk [Member] | ' | ' |
Financing Receivable Recorded Investment [Line Items] | ' | ' |
Installment plan receivables uncollectible accounts reserve | -4 | -3 |
PECO Energy Co [Member] | High Risk [Member] | ' | ' |
Financing Receivable Recorded Investment [Line Items] | ' | ' |
Installment plan receivables uncollectible accounts reserve | -17 | -11 |
Baltimore Gas and Electric Company [Member] | ' | ' |
Accounts Notes And Loans Receivable Net Current [Abstract] | ' | ' |
Allowance for uncollectible accounts | $38 | $40 |
Property_Plant_and_Equipment_D
Property, Plant and Equipment (Details) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 | ||
In Millions, unless otherwise specified | ||||
Property Plant And Equipment [Line Items] | ' | ' | ||
Less: accumulated depreciation | ($13,366) | [1] | ($12,184) | [2] |
Property, plant and equipment, net | 46,495 | 45,186 | ||
Property Plant And Equipment Footnotes [Abstract] | ' | ' | ||
Accumulated amortization of nuclear fuel | 2,365 | 2,078 | ||
Exelon Generation Co L L C [Member] | ' | ' | ||
Property Plant And Equipment [Line Items] | ' | ' | ||
Less: accumulated depreciation | -6,848 | [1] | -6,014 | [2] |
Property, plant and equipment, net | 19,797 | 19,531 | ||
Property Plant And Equipment Footnotes [Abstract] | ' | ' | ||
Accumulated amortization of nuclear fuel | 2,365 | 2,078 | ||
Commonwealth Edison Co [Member] | ' | ' | ||
Property Plant And Equipment [Line Items] | ' | ' | ||
Less: accumulated depreciation | -3,107 | -2,998 | ||
Property, plant and equipment, net | 14,444 | 13,826 | ||
PECO Energy Co [Member] | ' | ' | ||
Property Plant And Equipment [Line Items] | ' | ' | ||
Less: accumulated depreciation | -2,914 | -2,797 | ||
Property, plant and equipment, net | 6,270 | 6,078 | ||
Baltimore Gas and Electric Company [Member] | ' | ' | ||
Property Plant And Equipment [Line Items] | ' | ' | ||
Less: accumulated depreciation | -2,658 | -2,595 | ||
Property, plant and equipment, net | $5,713 | $5,498 | ||
[1] | Includes accumulated amortization of nuclear fuel in the reactor core of $2,365 million. | |||
[2] | Includes accumulated amortization of nuclear fuel in the reactor core of $2,078 million. |
Fair_Value_of_Financial_Assets3
Fair Value of Financial Assets and Liabilities (Fair Value By Balance Sheet Grouping) (Details) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
In Millions, unless otherwise specified | ||
Carrying Reported Amount Fair Value Disclosure [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | $217 | $214 |
Long-term debt (including amounts due within one year) | 19,565 | 18,745 |
Long-term debt to financing trusts | 648 | 648 |
Spent nuclear fuel obligation | 1,021 | 1,020 |
Preferred securities of subsidiary | ' | 87 |
Estimate Of Fair Value Fair Value Disclosure [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | 217 | 214 |
Long-term debt (including amounts due within one year) | 20,268 | 20,520 |
Long-term debt to financing trusts | 631 | 664 |
Spent nuclear fuel obligation | 782 | 763 |
Preferred securities of subsidiary | ' | 82 |
Estimate Of Fair Value Fair Value Disclosure [Member] | Fair Value Inputs Level 1 [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | 3 | 4 |
Estimate Of Fair Value Fair Value Disclosure [Member] | Fair Value Inputs Level 2 [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | 214 | 210 |
Long-term debt (including amounts due within one year) | 19,203 | 20,244 |
Spent nuclear fuel obligation | 782 | 763 |
Preferred securities of subsidiary | ' | 82 |
Estimate Of Fair Value Fair Value Disclosure [Member] | Fair Value Inputs Level 3 [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Long-term debt (including amounts due within one year) | 1,065 | 276 |
Long-term debt to financing trusts | 631 | 664 |
Exelon Generation Co L L C [Member] | Carrying Reported Amount Fair Value Disclosure [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | 21 | ' |
Long-term debt (including amounts due within one year) | 7,809 | 7,483 |
Spent nuclear fuel obligation | 1,021 | 1,020 |
Exelon Generation Co L L C [Member] | Estimate Of Fair Value Fair Value Disclosure [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | 21 | ' |
Long-term debt (including amounts due within one year) | 7,791 | 7,849 |
Spent nuclear fuel obligation | 782 | 763 |
Exelon Generation Co L L C [Member] | Estimate Of Fair Value Fair Value Disclosure [Member] | Fair Value Inputs Level 2 [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | 21 | ' |
Long-term debt (including amounts due within one year) | 6,744 | 7,591 |
Spent nuclear fuel obligation | 782 | 763 |
Exelon Generation Co L L C [Member] | Estimate Of Fair Value Fair Value Disclosure [Member] | Fair Value Inputs Level 3 [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Long-term debt (including amounts due within one year) | 1,047 | 258 |
Commonwealth Edison Co [Member] | Carrying Reported Amount Fair Value Disclosure [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | 153 | ' |
Long-term debt (including amounts due within one year) | 5,674 | 5,567 |
Long-term debt to financing trusts | 206 | 206 |
Commonwealth Edison Co [Member] | Estimate Of Fair Value Fair Value Disclosure [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | 153 | ' |
Long-term debt (including amounts due within one year) | 6,257 | 6,548 |
Long-term debt to financing trusts | 195 | 212 |
Commonwealth Edison Co [Member] | Estimate Of Fair Value Fair Value Disclosure [Member] | Fair Value Inputs Level 2 [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | 153 | ' |
Long-term debt (including amounts due within one year) | 6,240 | 6,530 |
Commonwealth Edison Co [Member] | Estimate Of Fair Value Fair Value Disclosure [Member] | Fair Value Inputs Level 3 [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Long-term debt (including amounts due within one year) | 17 | 18 |
Long-term debt to financing trusts | 195 | 212 |
PECO Energy Co [Member] | Carrying Reported Amount Fair Value Disclosure [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | 0 | 210 |
Long-term debt (including amounts due within one year) | 2,496 | 1,947 |
Long-term debt to financing trusts | 184 | 184 |
Preferred securities of subsidiary | ' | 87 |
PECO Energy Co [Member] | Estimate Of Fair Value Fair Value Disclosure [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | 0 | 210 |
Long-term debt (including amounts due within one year) | 2,678 | 2,264 |
Long-term debt to financing trusts | 182 | 188 |
Preferred securities of subsidiary | ' | 82 |
PECO Energy Co [Member] | Estimate Of Fair Value Fair Value Disclosure [Member] | Fair Value Inputs Level 2 [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | 0 | 210 |
Long-term debt (including amounts due within one year) | 2,678 | 2,264 |
Preferred securities of subsidiary | ' | 82 |
PECO Energy Co [Member] | Estimate Of Fair Value Fair Value Disclosure [Member] | Fair Value Inputs Level 3 [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Long-term debt to financing trusts | 182 | 188 |
Baltimore Gas and Electric Company [Member] | Carrying Reported Amount Fair Value Disclosure [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | 43 | ' |
Long-term debt (including amounts due within one year) | 2,045 | 2,178 |
Long-term debt to financing trusts | 258 | 258 |
Baltimore Gas and Electric Company [Member] | Estimate Of Fair Value Fair Value Disclosure [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | 43 | ' |
Long-term debt (including amounts due within one year) | 2,204 | 2,468 |
Long-term debt to financing trusts | 254 | 263 |
Baltimore Gas and Electric Company [Member] | Estimate Of Fair Value Fair Value Disclosure [Member] | Fair Value Inputs Level 1 [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | 3 | ' |
Baltimore Gas and Electric Company [Member] | Estimate Of Fair Value Fair Value Disclosure [Member] | Fair Value Inputs Level 2 [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | 40 | ' |
Long-term debt (including amounts due within one year) | 2,204 | 2,468 |
Baltimore Gas and Electric Company [Member] | Estimate Of Fair Value Fair Value Disclosure [Member] | Fair Value Inputs Level 3 [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Long-term debt to financing trusts | $254 | $263 |
Fair_Value_of_Financial_Assets4
Fair Value of Financial Assets and Liabilities (Fair Value Measurements, Recurring and Nonrecurring) (Details) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | ||
In Millions, unless otherwise specified | |||||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | $1 | [1] | $995 | [1] | ' |
Fixed income [Abstract] | ' | ' | ' | ||
Other investments | 12 | 19 | ' | ||
Deferred compensation | -108 | -102 | ' | ||
Total assets | 9,815 | 10,785 | ' | ||
Total liabilities | -452 | -735 | ' | ||
Total net assets | 9,363 | 10,050 | ' | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Deferred compensation | 108 | 102 | ' | ||
Mark-to-market derivative liabilities (current liabilities) | 126 | 352 | ' | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | 218 | 281 | ' | ||
Nuclear Decommissioning Trust Fund Investments [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 558 | 245 | ' | ||
Equity Securities [Abstract] | ' | ' | ' | ||
Equity securities | 1,600 | 1,480 | ' | ||
Exchange traded funds | 110 | ' | ' | ||
Commingled funds | 2,114 | 1,933 | ' | ||
Equity securities subtotal | 3,824 | 3,413 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 938 | 1,057 | ' | ||
Debt securities issued by states of the United States and political subdivisions of the states | 295 | 321 | ' | ||
Debt securities issued by foreign governments | 84 | 93 | ' | ||
Corporate debt securities | 1,712 | 1,788 | ' | ||
Federal agency mortgage-backed securities | 16 | 24 | ' | ||
Commercial mortgage-backed securities (non-agency) | 41 | 45 | ' | ||
Residential mortgage-backed securities (non-agency) | 7 | 11 | ' | ||
Mutual funds fixed income | 29 | 23 | ' | ||
Fixed income subtotal | 3,122 | 3,362 | ' | ||
Direct lending securities | 245 | 183 | ' | ||
Other debt obligations | 14 | 15 | ' | ||
Nuclear decommissioning trust fund investments subtotal | 7,763 | [2] | 7,218 | [2] | ' |
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Net assets (liabilities) excluded from nuclear decommissioning trust fund investments | 13 | 30 | ' | ||
Pledged Assets For Zion Station Decommissioning [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 25 | 23 | ' | ||
Equity Securities [Abstract] | ' | ' | ' | ||
Equity securities | 4 | 14 | ' | ||
Commingled funds | ' | 9 | ' | ||
Equity securities subtotal | 4 | 23 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 96 | 130 | ' | ||
Debt securities issued by states of the United States and political subdivisions of the states | 24 | 37 | ' | ||
Corporate debt securities | 217 | 249 | ' | ||
Federal agency mortgage-backed securities | 7 | 49 | ' | ||
Commercial mortgage-backed securities (non-agency) | ' | 6 | ' | ||
Fixed income subtotal | 344 | 471 | ' | ||
Direct lending securities | 106 | 89 | ' | ||
Other debt obligations | ' | 1 | ' | ||
Pledged assets for Zion Station decommissioning subtotal | 479 | [3] | 607 | [3] | ' |
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Net assets (liabilities) excluded from pledged assets | 7 | 7 | ' | ||
Rabbi Trust Investments [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 2 | 2 | ' | ||
Equity Securities [Abstract] | ' | ' | ' | ||
Equity securities subtotal | 0 | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Mutual funds | 49 | [4],[5] | 69 | [4],[5] | ' |
Rabbi trust investments subtotal | 51 | 71 | ' | ||
Deferred compensation | -49 | -53 | ' | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Deferred compensation | 49 | 53 | ' | ||
Supplemental executive retirement plan fair value | 0 | 16 | ' | ||
Cash surrender value of life insurance investments excluded from Rabbi Trust investments | 30 | 28 | ' | ||
Derivative Financial Instruments Liabilities [Member] | ' | ' | ' | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Fair value of energy swap contract current liability | 16 | 18 | ' | ||
Fair value of energy swap contract noncurrent liability | 106 | 49 | ' | ||
Commodity Mark To Market Derivative Assets [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Other derivatives | 3,784 | 4,675 | ' | ||
Proprietary trading | 2,024 | 3,193 | ' | ||
Effect of netting and allocation of collateral received/(paid) | -4,347 | [6] | -6,056 | [6] | ' |
Mark-to-market subtotal | 1,461 | 1,812 | [7] | ' | |
Commodity Mark To Market Derivative Liabilities [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Other derivatives | -2,845 | -3,566 | ' | ||
Proprietary trading | -1,976 | -3,121 | ' | ||
Effect of netting and allocation of collateral received/(paid) | 4,493 | [6] | 6,087 | [6] | ' |
Mark-to-market subtotal | -328 | [7] | -600 | [7] | ' |
Interest Rate Mark To Market Derivative Assets [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Effect of netting and allocation of collateral received/(paid) | -35 | 51 | ' | ||
Interest rate mark to market | 83 | 114 | ' | ||
Interest rate mark-to-market Subtotal | 48 | 63 | ' | ||
Interest Rate Mark To Market Derivative Liabilities [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Effect of netting and allocation of collateral received/(paid) | -35 | 51 | ' | ||
Interest rate mark to market | -51 | 84 | ' | ||
Interest rate mark-to-market Subtotal | -16 | 33 | ' | ||
Fair Value Inputs Level 1 [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 1 | [1] | 995 | [1] | ' |
Fixed income [Abstract] | ' | ' | ' | ||
Other investments | 1 | 2 | ' | ||
Deferred compensation | 0 | 0 | ' | ||
Total assets | 3,308 | 4,062 | ' | ||
Total liabilities | -92 | -83 | ' | ||
Total net assets | 3,216 | 3,979 | ' | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Deferred compensation | 0 | 0 | ' | ||
Collateral received from counterparties, net of collateral paid to counterparties | 108 | 219 | ' | ||
Fair Value Inputs Level 1 [Member] | Nuclear Decommissioning Trust Fund Investments [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 558 | 245 | ' | ||
Equity Securities [Abstract] | ' | ' | ' | ||
Equity securities | 1,600 | 1,480 | ' | ||
Exchange traded funds | 110 | ' | ' | ||
Commingled funds | 0 | ' | ' | ||
Equity securities subtotal | 1,710 | 1,480 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 938 | 1,057 | ' | ||
Debt securities issued by states of the United States and political subdivisions of the states | 0 | ' | ' | ||
Debt securities issued by foreign governments | 0 | ' | ' | ||
Corporate debt securities | 0 | ' | ' | ||
Federal agency mortgage-backed securities | 0 | ' | ' | ||
Commercial mortgage-backed securities (non-agency) | 0 | ' | ' | ||
Residential mortgage-backed securities (non-agency) | 0 | ' | ' | ||
Mutual funds fixed income | 0 | ' | ' | ||
Fixed income subtotal | 938 | 1,057 | ' | ||
Direct lending securities | 0 | ' | ' | ||
Other debt obligations | 0 | ' | ' | ||
Nuclear decommissioning trust fund investments subtotal | 3,206 | [2] | 2,782 | [2] | ' |
Fair Value Inputs Level 1 [Member] | Pledged Assets For Zion Station Decommissioning [Member] | ' | ' | ' | ||
Equity Securities [Abstract] | ' | ' | ' | ||
Equity securities | 4 | 14 | ' | ||
Equity securities subtotal | 4 | 14 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 89 | 118 | ' | ||
Debt securities issued by states of the United States and political subdivisions of the states | 0 | ' | ' | ||
Corporate debt securities | 0 | ' | ' | ||
Federal agency mortgage-backed securities | 0 | ' | ' | ||
Fixed income subtotal | 89 | 118 | ' | ||
Direct lending securities | 0 | ' | ' | ||
Pledged assets for Zion Station decommissioning subtotal | 93 | [3] | 132 | [3] | ' |
Fair Value Inputs Level 1 [Member] | Rabbi Trust Investments [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 2 | 2 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Mutual funds | 49 | [4],[5] | 69 | [4],[5] | ' |
Rabbi trust investments subtotal | 51 | 71 | ' | ||
Fair Value Inputs Level 1 [Member] | Commodity Mark To Market Derivative Assets [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Other derivatives | 540 | 861 | ' | ||
Proprietary trading | 666 | 1,042 | ' | ||
Effect of netting and allocation of collateral received/(paid) | -1,251 | [6] | -1,823 | [6] | ' |
Mark-to-market subtotal | ' | 80 | [7] | ' | |
Fair Value Inputs Level 1 [Member] | Commodity Mark To Market Derivative Liabilities [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Other derivatives | -764 | -1,041 | ' | ||
Proprietary trading | -686 | -1,084 | ' | ||
Effect of netting and allocation of collateral received/(paid) | 1,359 | [6] | 2,042 | [6] | ' |
Mark-to-market subtotal | -91 | [7] | -83 | [7] | ' |
Fair Value Inputs Level 1 [Member] | Interest Rate Mark To Market Derivative Assets [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Effect of netting and allocation of collateral received/(paid) | -33 | ' | ' | ||
Mark-to-market subtotal | -45 | ' | ' | ||
Interest rate mark to market | 34 | ' | ' | ||
Interest rate mark-to-market Subtotal | 1 | 0 | ' | ||
Fair Value Inputs Level 1 [Member] | Interest Rate Mark To Market Derivative Liabilities [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Effect of netting and allocation of collateral received/(paid) | 33 | ' | ' | ||
Interest rate mark to market | -34 | ' | ' | ||
Interest rate mark-to-market Subtotal | -1 | 0 | ' | ||
Fair Value Inputs Level 2 [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 0 | [1] | 0 | [1] | ' |
Fixed income [Abstract] | ' | ' | ' | ||
Deferred compensation | -108 | -102 | ' | ||
Total assets | 5,579 | 5,778 | ' | ||
Total liabilities | -133 | -363 | ' | ||
Total net assets | 5,446 | 5,415 | ' | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Deferred compensation | 108 | 102 | ' | ||
Collateral received from counterparties, net of collateral paid to counterparties | 58 | -155 | ' | ||
Fair Value Inputs Level 2 [Member] | Nuclear Decommissioning Trust Fund Investments [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 0 | ' | ' | ||
Equity Securities [Abstract] | ' | ' | ' | ||
Equity securities | 0 | ' | ' | ||
Commingled funds | 2,114 | 1,933 | ' | ||
Equity securities subtotal | 2,114 | 1,933 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 0 | ' | ' | ||
Debt securities issued by states of the United States and political subdivisions of the states | 295 | 321 | ' | ||
Debt securities issued by foreign governments | 84 | 93 | ' | ||
Corporate debt securities | 1,712 | 1,788 | ' | ||
Federal agency mortgage-backed securities | 16 | 24 | ' | ||
Commercial mortgage-backed securities (non-agency) | 41 | 45 | ' | ||
Residential mortgage-backed securities (non-agency) | 7 | 11 | ' | ||
Mutual funds fixed income | 29 | 23 | ' | ||
Fixed income subtotal | 2,184 | 2,305 | ' | ||
Direct lending securities | 0 | ' | ' | ||
Other debt obligations | 14 | 15 | ' | ||
Nuclear decommissioning trust fund investments subtotal | 4,312 | [2] | 4,253 | [2] | ' |
Fair Value Inputs Level 2 [Member] | Pledged Assets For Zion Station Decommissioning [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 25 | 23 | ' | ||
Equity Securities [Abstract] | ' | ' | ' | ||
Commingled funds | ' | 9 | ' | ||
Equity securities subtotal | ' | 9 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 7 | 12 | ' | ||
Debt securities issued by states of the United States and political subdivisions of the states | 24 | 37 | ' | ||
Corporate debt securities | 217 | 249 | ' | ||
Federal agency mortgage-backed securities | 7 | 49 | ' | ||
Commercial mortgage-backed securities (non-agency) | ' | 6 | ' | ||
Fixed income subtotal | 255 | 353 | ' | ||
Direct lending securities | 0 | ' | ' | ||
Other debt obligations | ' | 1 | ' | ||
Pledged assets for Zion Station decommissioning subtotal | 280 | [3] | 386 | [3] | ' |
Fair Value Inputs Level 2 [Member] | Rabbi Trust Investments [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 0 | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Mutual funds | 0 | [4],[5] | ' | ' | |
Rabbi trust investments subtotal | 0 | 0 | ' | ||
Fair Value Inputs Level 2 [Member] | Derivative Financial Instruments Assets [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Other investments | 0 | ' | ' | ||
Fair Value Inputs Level 2 [Member] | Commodity Mark To Market Derivative Assets [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Other derivatives | 2,541 | 3,173 | ' | ||
Proprietary trading | 1,184 | 2,078 | ' | ||
Effect of netting and allocation of collateral received/(paid) | -2,785 | [6] | -4,175 | [6] | ' |
Mark-to-market subtotal | 940 | 1,076 | [7] | ' | |
Fair Value Inputs Level 2 [Member] | Commodity Mark To Market Derivative Liabilities [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Other derivatives | -1,718 | -2,289 | ' | ||
Proprietary trading | -1,135 | -1,959 | ' | ||
Effect of netting and allocation of collateral received/(paid) | 2,843 | [6] | 4,020 | [6] | ' |
Mark-to-market subtotal | -10 | [7] | -228 | [7] | ' |
Fair Value Inputs Level 2 [Member] | Interest Rate Mark To Market Derivative Assets [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Effect of netting and allocation of collateral received/(paid) | -2 | 51 | ' | ||
Interest rate mark to market | 49 | 114 | ' | ||
Interest rate mark-to-market Subtotal | 47 | 63 | ' | ||
Fair Value Inputs Level 2 [Member] | Interest Rate Mark To Market Derivative Liabilities [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Effect of netting and allocation of collateral received/(paid) | -2 | -51 | ' | ||
Interest rate mark to market | -17 | 84 | ' | ||
Interest rate mark-to-market Subtotal | -15 | 33 | ' | ||
Fair Value Inputs Level 3 [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 0 | [1] | 0 | [1] | ' |
Fixed income [Abstract] | ' | ' | ' | ||
Effect of netting and allocation of collateral received/(paid) | 291 | [6] | ' | ' | |
Other investments | 11 | 17 | ' | ||
Deferred compensation | 0 | 0 | ' | ||
Total assets | 928 | 945 | ' | ||
Total liabilities | -227 | -289 | ' | ||
Total net assets | 701 | 656 | ' | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Deferred compensation | 0 | 0 | ' | ||
Collateral received from counterparties, net of collateral paid to counterparties | -20 | -33 | ' | ||
Fair Value Inputs Level 3 [Member] | Nuclear Decommissioning Trust Fund Investments [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 0 | ' | ' | ||
Equity Securities [Abstract] | ' | ' | ' | ||
Equity securities | 0 | 0 | ' | ||
Commingled funds | 0 | ' | ' | ||
Equity securities subtotal | 0 | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 0 | ' | ' | ||
Debt securities issued by states of the United States and political subdivisions of the states | 0 | ' | ' | ||
Debt securities issued by foreign governments | 0 | ' | ' | ||
Corporate debt securities | 0 | ' | ' | ||
Federal agency mortgage-backed securities | 0 | ' | ' | ||
Commercial mortgage-backed securities (non-agency) | 0 | ' | ' | ||
Residential mortgage-backed securities (non-agency) | 0 | ' | ' | ||
Mutual funds fixed income | 0 | ' | ' | ||
Fixed income subtotal | 0 | 0 | ' | ||
Direct lending securities | 245 | 183 | ' | ||
Other debt obligations | 0 | ' | ' | ||
Nuclear decommissioning trust fund investments subtotal | 245 | [2] | 183 | [2] | ' |
Fair Value Inputs Level 3 [Member] | Pledged Assets For Zion Station Decommissioning [Member] | ' | ' | ' | ||
Equity Securities [Abstract] | ' | ' | ' | ||
Equity securities subtotal | ' | 0 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 0 | ' | ' | ||
Debt securities issued by states of the United States and political subdivisions of the states | 0 | ' | ' | ||
Corporate debt securities | 0 | ' | ' | ||
Federal agency mortgage-backed securities | 0 | ' | ' | ||
Fixed income subtotal | 0 | 0 | ' | ||
Direct lending securities | 106 | 89 | ' | ||
Pledged assets for Zion Station decommissioning subtotal | 106 | [3] | 89 | [3] | ' |
Fair Value Inputs Level 3 [Member] | Rabbi Trust Investments [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 0 | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Mutual funds | 0 | [4],[5] | ' | ' | |
Rabbi trust investments subtotal | 0 | 0 | ' | ||
Fair Value Inputs Level 3 [Member] | Commodity Mark To Market Derivative Assets [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Other derivatives | 703 | 641 | ' | ||
Proprietary trading | 174 | 73 | ' | ||
Effect of netting and allocation of collateral received/(paid) | -311 | [6] | -58 | [6] | ' |
Mark-to-market subtotal | 566 | 656 | [7] | ' | |
Fair Value Inputs Level 3 [Member] | Commodity Mark To Market Derivative Liabilities [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Other derivatives | -363 | -236 | ' | ||
Proprietary trading | -155 | -78 | ' | ||
Effect of netting and allocation of collateral received/(paid) | ' | 25 | [6] | ' | |
Mark-to-market subtotal | -227 | [7] | -289 | [7] | ' |
Fair Value Inputs Level 3 [Member] | Interest Rate Mark To Market Derivative Assets [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Interest rate mark to market | 0 | ' | ' | ||
Interest rate mark-to-market Subtotal | 0 | 0 | ' | ||
Fair Value Inputs Level 3 [Member] | Interest Rate Mark To Market Derivative Liabilities [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Interest rate mark to market | 0 | ' | ' | ||
Interest rate mark-to-market Subtotal | 0 | 0 | ' | ||
Exelon Generation Co L L C [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 674 | 487 | [1] | ' | |
Fixed income [Abstract] | ' | ' | ' | ||
Other investments | 12 | 19 | ' | ||
Deferred compensation | -27 | -28 | ' | ||
Total assets | 10,436 | 10,433 | ' | ||
Total liabilities | -249 | -594 | ' | ||
Total net assets | 10,187 | 9,839 | ' | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Deferred compensation | 27 | 28 | ' | ||
Mark-to-market derivative liabilities (current liabilities) | 110 | 334 | ' | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | 112 | 232 | ' | ||
Exelon Generation Co L L C [Member] | Nuclear Decommissioning Trust Fund Investments [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 558 | 245 | ' | ||
Equity Securities [Abstract] | ' | ' | ' | ||
Equity securities | 1,600 | 1,480 | ' | ||
Exchange traded funds | 110 | ' | ' | ||
Commingled funds | 2,114 | 1,933 | ' | ||
Equity securities subtotal | 3,824 | 3,413 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 938 | 1,057 | ' | ||
Debt securities issued by states of the United States and political subdivisions of the states | 295 | 321 | ' | ||
Debt securities issued by foreign governments | 84 | 93 | ' | ||
Corporate debt securities | 1,712 | 1,788 | ' | ||
Federal agency mortgage-backed securities | 16 | 24 | ' | ||
Commercial mortgage-backed securities (non-agency) | 41 | 45 | ' | ||
Residential mortgage-backed securities (non-agency) | 7 | 11 | ' | ||
Mutual funds fixed income | 29 | 23 | ' | ||
Fixed income subtotal | 3,122 | 3,362 | ' | ||
Direct lending securities | 245 | 183 | ' | ||
Other debt obligations | 14 | 15 | ' | ||
Nuclear decommissioning trust fund investments subtotal | 7,763 | [2] | 7,218 | [2] | ' |
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Net assets (liabilities) excluded from nuclear decommissioning trust fund investments | 13 | 30 | ' | ||
Exelon Generation Co L L C [Member] | Pledged Assets For Zion Station Decommissioning [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 25 | 23 | ' | ||
Equity Securities [Abstract] | ' | ' | ' | ||
Equity securities | 4 | 14 | ' | ||
Commingled funds | ' | 9 | ' | ||
Equity securities subtotal | 4 | 23 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 96 | 130 | ' | ||
Debt securities issued by states of the United States and political subdivisions of the states | 24 | 37 | ' | ||
Corporate debt securities | 217 | 249 | ' | ||
Federal agency mortgage-backed securities | 7 | 49 | ' | ||
Commercial mortgage-backed securities (non-agency) | ' | 6 | ' | ||
Fixed income subtotal | 344 | 471 | ' | ||
Direct lending securities | 106 | 89 | ' | ||
Other debt obligations | ' | 1 | ' | ||
Pledged assets for Zion Station decommissioning subtotal | 479 | [8] | 607 | [8] | ' |
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Net assets (liabilities) excluded from nuclear decommissioning trust fund investments | 7 | 7 | ' | ||
Exelon Generation Co L L C [Member] | Rabbi Trust Investments [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 0 | 1 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Mutual funds | 12 | [9] | 13 | [9] | ' |
Rabbi trust investments subtotal | 12 | 14 | ' | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash surrender value of life insurance investments excluded from Rabbi Trust investments | 9 | 8 | ' | ||
Exelon Generation Co L L C [Member] | Derivative Financial Instruments Assets [Member] | ' | ' | ' | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Fair value swap contract current asset | 0 | 226 | ' | ||
Fair value swap contract noncurrent asset | 0 | 0 | ' | ||
Exelon Generation Co L L C [Member] | Commodity Mark To Market Derivative Assets [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Other derivatives | 3,784 | 4,901 | ' | ||
Proprietary trading | 2,024 | 3,193 | ' | ||
Effect of netting and allocation of collateral received/(paid) | -4,347 | [6] | -6,056 | [6] | ' |
Mark-to-market subtotal | 1,461 | 2,038 | [10] | ' | |
Exelon Generation Co L L C [Member] | Commodity Mark To Market Derivative Liabilities [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Cash flow hedges | 0 | ' | ' | ||
Other derivatives | -2,723 | -3,499 | ' | ||
Proprietary trading | -1,976 | -3,121 | ' | ||
Effect of netting and allocation of collateral received/(paid) | 4,493 | [6] | 6,087 | [6] | ' |
Mark-to-market subtotal | -206 | -533 | ' | ||
Exelon Generation Co L L C [Member] | Interest Rate Mark To Market Derivative Assets [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Effect of netting and allocation of collateral received/(paid) | 35 | 51 | ' | ||
Interest rate mark to market | 70 | 101 | ' | ||
Interest rate mark-to-market Subtotal | 35 | 50 | ' | ||
Exelon Generation Co L L C [Member] | Interest Rate Mark To Market Derivative Liabilities [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Effect of netting and allocation of collateral received/(paid) | -35 | -51 | ' | ||
Interest rate mark to market | -51 | -84 | ' | ||
Interest rate mark-to-market Subtotal | -16 | -33 | ' | ||
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 674 | 487 | [1] | ' | |
Fixed income [Abstract] | ' | ' | ' | ||
Other investments | 1 | 2 | ' | ||
Deferred compensation | 0 | ' | ' | ||
Total assets | 3,942 | 3,497 | ' | ||
Total liabilities | -92 | -83 | ' | ||
Total net assets | 3,850 | 3,414 | ' | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Deferred compensation | 0 | ' | ' | ||
Collateral received from counterparties, net of collateral paid to counterparties | 108 | ' | 219 | ||
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member] | Nuclear Decommissioning Trust Fund Investments [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 558 | 245 | ' | ||
Equity Securities [Abstract] | ' | ' | ' | ||
Equity securities | 1,600 | 1,480 | ' | ||
Exchange traded funds | 110 | ' | ' | ||
Commingled funds | 0 | ' | ' | ||
Equity securities subtotal | 1,710 | 1,480 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 938 | 1,057 | ' | ||
Debt securities issued by states of the United States and political subdivisions of the states | 0 | ' | ' | ||
Fixed income subtotal | 938 | 1,057 | ' | ||
Other debt obligations | 0 | ' | ' | ||
Nuclear decommissioning trust fund investments subtotal | 3,206 | [2] | 2,782 | [2] | ' |
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member] | Pledged Assets For Zion Station Decommissioning [Member] | ' | ' | ' | ||
Equity Securities [Abstract] | ' | ' | ' | ||
Equity securities | 4 | 14 | ' | ||
Equity securities subtotal | 4 | 14 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 89 | 118 | ' | ||
Fixed income subtotal | 89 | 118 | ' | ||
Pledged assets for Zion Station decommissioning subtotal | 93 | [8] | 132 | [8] | ' |
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member] | Rabbi Trust Investments [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 0 | 1 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Mutual funds | 12 | [9] | 13 | [9] | ' |
Rabbi trust investments subtotal | 12 | 14 | ' | ||
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member] | Commodity Mark To Market Derivative Assets [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Other derivatives | 540 | 861 | ' | ||
Proprietary trading | 666 | 1,042 | ' | ||
Effect of netting and allocation of collateral received/(paid) | -1,251 | [6] | -1,823 | [6] | ' |
Mark-to-market subtotal | -45 | 80 | [10],[11] | ' | |
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member] | Commodity Mark To Market Derivative Liabilities [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Cash flow hedges | 0 | ' | ' | ||
Other derivatives | -764 | -1,041 | ' | ||
Proprietary trading | -686 | -1,084 | ' | ||
Effect of netting and allocation of collateral received/(paid) | 1,359 | [6] | 2,042 | [6] | ' |
Mark-to-market subtotal | -91 | -83 | ' | ||
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member] | Interest Rate Mark To Market Derivative Assets [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Effect of netting and allocation of collateral received/(paid) | 33 | ' | ' | ||
Interest rate mark to market | 34 | ' | ' | ||
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member] | Interest Rate Mark To Market Derivative Liabilities [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Effect of netting and allocation of collateral received/(paid) | -33 | ' | ' | ||
Interest rate mark to market | -34 | ' | ' | ||
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 2 [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 0 | 0 | [1] | ' | |
Fixed income [Abstract] | ' | ' | ' | ||
Deferred compensation | -27 | -28 | ' | ||
Total assets | 5,566 | 5,765 | ' | ||
Total liabilities | -52 | -289 | ' | ||
Total net assets | 5,514 | 5,476 | ' | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Deferred compensation | 27 | 28 | ' | ||
Collateral received from counterparties, net of collateral paid to counterparties | 58 | ' | -155 | ||
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 Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 0 | ' | ' | ||
Equity Securities [Abstract] | ' | ' | ' | ||
Equity securities | 0 | ' | ' | ||
Commingled funds | 2,114 | 1,933 | ' | ||
Equity securities subtotal | 2,114 | 1,933 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 0 | ' | ' | ||
Debt securities issued by states of the United States and political subdivisions of the states | 295 | 321 | ' | ||
Debt securities issued by foreign governments | 84 | 93 | ' | ||
Corporate debt securities | 1,712 | 1,788 | ' | ||
Federal agency mortgage-backed securities | 16 | 24 | ' | ||
Commercial mortgage-backed securities (non-agency) | 41 | 45 | ' | ||
Residential mortgage-backed securities (non-agency) | 7 | 11 | ' | ||
Mutual funds fixed income | 29 | 23 | ' | ||
Fixed income subtotal | 2,184 | 2,305 | ' | ||
Other debt obligations | 14 | 15 | ' | ||
Nuclear decommissioning trust fund investments subtotal | 4,312 | [2] | 4,253 | [2] | ' |
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 2 [Member] | Pledged Assets For Zion Station Decommissioning [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 25 | 23 | ' | ||
Equity Securities [Abstract] | ' | ' | ' | ||
Commingled funds | ' | 9 | ' | ||
Equity securities subtotal | ' | 9 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 7 | 12 | ' | ||
Debt securities issued by states of the United States and political subdivisions of the states | 24 | 37 | ' | ||
Corporate debt securities | 217 | 249 | ' | ||
Federal agency mortgage-backed securities | 7 | 49 | ' | ||
Commercial mortgage-backed securities (non-agency) | ' | 6 | ' | ||
Fixed income subtotal | 255 | 353 | ' | ||
Direct lending securities | 0 | ' | ' | ||
Other debt obligations | ' | 1 | ' | ||
Pledged assets for Zion Station decommissioning subtotal | 280 | [8] | 386 | [8] | ' |
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 2 [Member] | Rabbi Trust Investments [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Rabbi trust investments subtotal | ' | 0 | ' | ||
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 2 [Member] | Commodity Mark To Market Derivative Assets [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Other derivatives | 2,541 | 3,173 | ' | ||
Proprietary trading | 1,184 | 2,078 | ' | ||
Effect of netting and allocation of collateral received/(paid) | -2,785 | [6] | -4,175 | [6] | ' |
Mark-to-market subtotal | 940 | 1,076 | [10] | ' | |
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 2 [Member] | Commodity Mark To Market Derivative Liabilities [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Cash flow hedges | 0 | ' | ' | ||
Other derivatives | -1,718 | -2,289 | ' | ||
Proprietary trading | -1,135 | -1,959 | ' | ||
Effect of netting and allocation of collateral received/(paid) | 2,843 | [6] | 4,020 | [6] | ' |
Mark-to-market subtotal | -10 | -228 | ' | ||
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 2 [Member] | Interest Rate Mark To Market Derivative Assets [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Effect of netting and allocation of collateral received/(paid) | 2 | 51 | ' | ||
Interest rate mark to market | 36 | 101 | ' | ||
Interest rate mark-to-market Subtotal | 34 | 50 | ' | ||
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 2 [Member] | Interest Rate Mark To Market Derivative Liabilities [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Effect of netting and allocation of collateral received/(paid) | -2 | -51 | ' | ||
Interest rate mark to market | -17 | -84 | ' | ||
Interest rate mark-to-market Subtotal | -15 | -33 | ' | ||
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 0 | 0 | [1] | ' | |
Equity Securities [Abstract] | ' | ' | ' | ||
Equity securities | 0 | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Other investments | 11 | 17 | ' | ||
Deferred compensation | 0 | ' | ' | ||
Total assets | 928 | 1,171 | ' | ||
Total liabilities | -105 | -222 | ' | ||
Total net assets | 823 | 949 | ' | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Deferred compensation | 0 | ' | ' | ||
Collateral received from counterparties, net of collateral paid to counterparties | -20 | ' | -33 | ||
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Nuclear Decommissioning Trust Fund Investments [Member] | ' | ' | ' | ||
Equity Securities [Abstract] | ' | ' | ' | ||
Commingled funds | 0 | ' | ' | ||
Equity securities subtotal | 0 | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 0 | ' | ' | ||
Debt securities issued by states of the United States and political subdivisions of the states | 0 | ' | ' | ||
Mutual funds fixed income | 0 | ' | ' | ||
Fixed income subtotal | 0 | ' | ' | ||
Direct lending securities | 245 | 183 | ' | ||
Other debt obligations | 0 | ' | ' | ||
Nuclear decommissioning trust fund investments subtotal | 245 | [2] | 183 | [2] | ' |
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Pledged Assets For Zion Station Decommissioning [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Direct lending securities | 106 | 89 | ' | ||
Pledged assets for Zion Station decommissioning subtotal | 106 | [8] | 89 | [8] | ' |
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Rabbi Trust Investments [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Rabbi trust investments subtotal | ' | 0 | ' | ||
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Commodity Mark To Market Derivative Assets [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Other derivatives | 703 | 867 | ' | ||
Proprietary trading | 174 | 73 | ' | ||
Effect of netting and allocation of collateral received/(paid) | -311 | [6] | -58 | [11],[6] | ' |
Mark-to-market subtotal | 566 | 882 | [10],[11] | ' | |
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Commodity Mark To Market Derivative Liabilities [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Cash flow hedges | 0 | ' | ' | ||
Other derivatives | -241 | -169 | ' | ||
Proprietary trading | -155 | -78 | ' | ||
Effect of netting and allocation of collateral received/(paid) | 291 | [6] | 25 | [6] | ' |
Mark-to-market subtotal | -105 | -222 | ' | ||
Commonwealth Edison Co [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 0 | 111 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Deferred compensation | -8 | -8 | ' | ||
Total assets | 5 | 119 | ' | ||
Total liabilities | -130 | -301 | ' | ||
Total net assets | -125 | -182 | ' | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Deferred compensation | 8 | 8 | ' | ||
Mark-to-market derivative liabilities (current liabilities) | 16 | 18 | ' | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | 106 | 49 | ' | ||
Commonwealth Edison Co [Member] | Rabbi Trust Investments [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Mutual funds | 5 | 8 | ' | ||
Rabbi trust investments subtotal | 5 | 8 | ' | ||
Commonwealth Edison Co [Member] | Derivative Financial Instruments Assets [Member] | ' | ' | ' | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Fair value swap contract current asset | 0 | 226 | ' | ||
Fair value swap contract noncurrent asset | 0 | 0 | ' | ||
Commonwealth Edison Co [Member] | Derivative Financial Instruments Liabilities [Member] | ' | ' | ' | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Fair value of energy swap contract current liability | 16 | 18 | ' | ||
Fair value of energy swap contract noncurrent liability | 106 | 49 | ' | ||
Commonwealth Edison Co [Member] | Commodity Mark To Market Derivative Liabilities [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Mark-to-market subtotal | 122 | [11],[7] | 293 | [11],[7] | ' |
Commonwealth Edison Co [Member] | Fair Value Inputs Level 1 [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 0 | 111 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Deferred compensation | 0 | ' | ' | ||
Total assets | 5 | 119 | ' | ||
Total liabilities | 0 | 0 | ' | ||
Total net assets | 5 | 119 | ' | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Deferred compensation | 0 | ' | ' | ||
Commonwealth Edison Co [Member] | Fair Value Inputs Level 1 [Member] | Rabbi Trust Investments [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Mutual funds | 5 | 8 | ' | ||
Rabbi trust investments subtotal | 5 | 8 | ' | ||
Commonwealth Edison Co [Member] | Fair Value Inputs Level 1 [Member] | Derivative Financial Instruments Liabilities [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Mark-to-market subtotal | 0 | [11],[7] | ' | ' | |
Commonwealth Edison Co [Member] | Fair Value Inputs Level 2 [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 0 | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Deferred compensation | -8 | -8 | ' | ||
Total assets | 0 | 0 | ' | ||
Total liabilities | -8 | -8 | ' | ||
Total net assets | -8 | -8 | ' | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Deferred compensation | 8 | 8 | ' | ||
Commonwealth Edison Co [Member] | Fair Value Inputs Level 2 [Member] | Rabbi Trust Investments [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Mutual funds | 0 | ' | ' | ||
Rabbi trust investments subtotal | 0 | 0 | ' | ||
Commonwealth Edison Co [Member] | Fair Value Inputs Level 2 [Member] | Derivative Financial Instruments Liabilities [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Mark-to-market subtotal | 0 | [11],[7] | ' | ' | |
Commonwealth Edison Co [Member] | Fair Value Inputs Level 3 [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 0 | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Deferred compensation | 0 | ' | ' | ||
Total assets | 0 | 0 | ' | ||
Total liabilities | -122 | -293 | ' | ||
Total net assets | -122 | -293 | ' | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Deferred compensation | 0 | ' | ' | ||
Commonwealth Edison Co [Member] | Fair Value Inputs Level 3 [Member] | Rabbi Trust Investments [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Mutual funds | 0 | ' | ' | ||
Rabbi trust investments subtotal | 0 | 0 | ' | ||
Commonwealth Edison Co [Member] | Fair Value Inputs Level 3 [Member] | Commodity Mark To Market Derivative Liabilities [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Mark-to-market subtotal | 122 | [11],[7] | 293 | [11],[7] | ' |
PECO Energy Co [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 583 | 346 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Deferred compensation | -16 | -18 | ' | ||
Total assets | 592 | 355 | ' | ||
Total liabilities | -16 | -18 | ' | ||
Total net assets | 576 | 337 | ' | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Deferred compensation | 16 | 18 | ' | ||
PECO Energy Co [Member] | Rabbi Trust Investments [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Mutual funds | 9 | 9 | ' | ||
Rabbi trust investments subtotal | 9 | [12],[13] | 9 | [12],[13] | ' |
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash surrender value of life insurance investments excluded from Rabbi Trust investments | 14 | 13 | ' | ||
PECO Energy Co [Member] | Fair Value Inputs Level 1 [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 583 | 346 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Total assets | 592 | 355 | ' | ||
Total net assets | 592 | 355 | ' | ||
PECO Energy Co [Member] | Fair Value Inputs Level 1 [Member] | Rabbi Trust Investments [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Mutual funds | 9 | 9 | ' | ||
Rabbi trust investments subtotal | 9 | [12],[13] | 9 | [12],[13] | ' |
PECO Energy Co [Member] | Fair Value Inputs Level 2 [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Deferred compensation | -16 | -18 | ' | ||
Total liabilities | -16 | -18 | ' | ||
Total net assets | -16 | -18 | ' | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Deferred compensation | 16 | 18 | ' | ||
PECO Energy Co [Member] | Fair Value Inputs Level 2 [Member] | Rabbi Trust Investments [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Mutual funds | ' | 0 | ' | ||
PECO Energy Co [Member] | Fair Value Inputs Level 3 [Member] | Rabbi Trust Investments [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Mutual funds | ' | 0 | ' | ||
Baltimore Gas and Electric Company [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 53 | 33 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Deferred compensation | -5 | -5 | ' | ||
Total assets | 58 | 38 | ' | ||
Total liabilities | -5 | -5 | ' | ||
Total net assets | 53 | 33 | ' | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Deferred compensation | 5 | 5 | ' | ||
Baltimore Gas and Electric Company [Member] | Rabbi Trust Investments [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Mutual funds | 5 | [12] | 5 | [12] | ' |
Rabbi trust investments subtotal | 5 | 5 | [12] | ' | |
Baltimore Gas and Electric Company [Member] | Fair Value Inputs Level 1 [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 53 | 33 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Total assets | 58 | 38 | ' | ||
Total net assets | 58 | 38 | ' | ||
Baltimore Gas and Electric Company [Member] | Fair Value Inputs Level 1 [Member] | Rabbi Trust Investments [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Mutual funds | 5 | [12] | 5 | [12] | ' |
Rabbi trust investments subtotal | 5 | 5 | [12] | ' | |
Baltimore Gas and Electric Company [Member] | Fair Value Inputs Level 2 [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Rabbi trust investments subtotal | 0 | ' | ' | ||
Deferred compensation | -5 | -5 | ' | ||
Total assets | 0 | ' | ' | ||
Total liabilities | -5 | -5 | ' | ||
Total net assets | -5 | -5 | ' | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Deferred compensation | 5 | 5 | ' | ||
Baltimore Gas and Electric Company [Member] | Fair Value Inputs Level 2 [Member] | Rabbi Trust Investments [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Mutual funds | 0 | ' | ' | ||
Rabbi trust investments subtotal | 0 | ' | ' | ||
Baltimore Gas and Electric Company [Member] | Fair Value Inputs Level 3 [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Rabbi trust investments subtotal | 0 | ' | ' | ||
Total assets | 0 | ' | ' | ||
Total net assets | 0 | ' | ' | ||
Baltimore Gas and Electric Company [Member] | Fair Value Inputs Level 3 [Member] | Rabbi Trust Investments [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Mutual funds | 0 | ' | ' | ||
Rabbi trust investments subtotal | $0 | ' | ' | ||
[1] | Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value. | ||||
[2] | Excludes net assets of $13 million and $30 million at September 30, 2013 and December 31, 2012, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases. | ||||
[3] | Excludes net assets of $7 million at both September 30, 2013 and December 31, 2012. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases. | ||||
[4] | The mutual funds held by the Rabbi trusts include $49 million related to deferred compensation at September 30, 2013, and $53 million related to deferred compensation and $16 million related to Supplemental Executive Retirement Plan at December 31, 2012. . | ||||
[5] | Excludes $30 million and $28 million of the cash surrender value of life insurance investments at September 30, 2013 and December 31, 2012, respectively. | ||||
[6] | Includes collateral postings (received) from counterparties. Collateral posted (received) from counterparties, net of collateral paid to counterparties, totaled $108 million, $58 million and $(20) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of September 30, 2013. Collateral posted (received) from counterparties, net of collateral paid to counterparties, totaled $219 million, $(155) million and $(33) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2012. | ||||
[7] | The Level 3 balance includes the current and noncurrent liability of $16 million and $106 million at September 30, 2013, respectively, and $18 million and $49 million at December 31, 2012, respectively, related to floating-to-fixed energy swap contracts with unaffiliated suppliers. | ||||
[8] | Excludes net assets of $7 at both September 30, 2013 December 31, 2012. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases. | ||||
[9] | Excludes $9 million and $8 million of the cash surrender value of life insurance investments at September 30, 2013 and December 31, 2012, respectively. | ||||
[10] | The level 3 balance includes current assets for Generation of $226 million at December 31, 2012, related to the fair value of Generationbs financial swap contract with ComEd, which eliminates upon consolidation in Exelonbs Consolidated Financial Statements. | ||||
[11] | The Level 3 balance includes the current liability of $226 million at December 31, 2012, related to the fair value of ComEd's financial swap contract with Generation which eliminated upon consolidation in Exelon's Consolidated Financial Statements. | ||||
[12] | Excludes $14 million and $13 million of the cash surrender value of life insurance investments at September 30, 2013 and December 31, 2012, respectively. | ||||
[13] | B B |
Fair_Value_of_Financial_Assets5
Fair Value of Financial Assets and Liabilities (Fair Value Assets Liabilities Measured On Recurring Basis Unobservable Input Reconciliation) (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||||||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | ||||
Fair Value Inputs Level 3 [Member] | ' | ' | ' | ' | ||||
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract] | ' | ' | ' | ' | ||||
Beginning balance | $793 | $425 | $656 | $67 | ||||
Total realized / unrealized gains (losses) | ' | ' | ' | ' | ||||
Included in income | -32 | -97 | 1 | -78 | ||||
Included in payable for Zion Station decommissioning | 0 | ' | 1 | 0 | ||||
Included in regulatory assets | -38 | 43 | -47 | 38 | ||||
Change in collateral | -30 | -15 | 13 | -7 | ||||
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract] | ' | ' | ' | ' | ||||
Purchases | 41 | 18 | 151 | 437 | ||||
Sales | -29 | 0 | -70 | -9 | ||||
Settlements | -3 | ' | -11 | ' | ||||
Transfers into Level 3 - (Asset) / Liability | 4 | 0 | 11 | -34 | ||||
Transfers out of Level 3 - (Asset) / Liability | -5 | 0 | -4 | -39 | ||||
Ending balance | 701 | 375 | 701 | 375 | ||||
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities | 51 | -42 | 160 | 62 | ||||
Nuclear Decommissioning Trust Fund Investment Level Three Asset [Member] | Fair Value Inputs Level 3 [Member] | ' | ' | ' | ' | ||||
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract] | ' | ' | ' | ' | ||||
Beginning balance | 240 | 54 | 183 | 13 | ||||
Total realized / unrealized gains (losses) | ' | ' | ' | ' | ||||
Included in income | 0 | ' | 2 | ' | ||||
Included in regulatory assets | -1 | 2 | 8 | 2 | ||||
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract] | ' | ' | ' | ' | ||||
Purchases | 23 | 14 | 90 | 55 | ||||
Sales | -14 | ' | -27 | ' | ||||
Settlements | -3 | ' | -11 | ' | ||||
Ending balance | 245 | 70 | 245 | 70 | ||||
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities | 0 | ' | 1 | ' | ||||
Pledged Assets For Zion Station Decommissioning [Member] | Fair Value Inputs Level 3 [Member] | ' | ' | ' | ' | ||||
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract] | ' | ' | ' | ' | ||||
Beginning balance | 111 | 59 | 89 | 37 | ||||
Total realized / unrealized gains (losses) | ' | ' | ' | ' | ||||
Included in payable for Zion Station decommissioning | 0 | 1 | 1 | 0 | ||||
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract] | ' | ' | ' | ' | ||||
Purchases | 10 | 4 | 43 | 36 | ||||
Sales | -15 | 0 | -27 | -9 | ||||
Ending balance | 106 | 64 | 106 | 64 | ||||
Derivative [Member] | Fair Value Inputs Level 3 [Member] | ' | ' | ' | ' | ||||
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract] | ' | ' | ' | ' | ||||
Beginning balance | 431 | 295 | 367 | 17 | ||||
Total realized / unrealized gains (losses) | ' | ' | ' | ' | ||||
Included in income | -32 | [1] | -97 | [2] | -1 | [1],[3] | -78 | [2],[4] |
Included in regulatory assets | -37 | 41 | [5] | -55 | [6],[7] | 36 | [5] | |
Change in collateral | -30 | -15 | 13 | -7 | ||||
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract] | ' | ' | ' | ' | ||||
Purchases | 8 | ' | 16 | 329 | [8] | |||
Sales | 0 | ' | -8 | ' | ||||
Transfers into Level 3 - (Asset) / Liability | 4 | 0 | 11 | -34 | ||||
Transfers out of Level 3 - (Asset) / Liability | -5 | 0 | -4 | -39 | ||||
Ending balance | 339 | 224 | 339 | 224 | ||||
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities | 51 | -42 | 159 | 62 | ||||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract] | ' | ' | ' | ' | ||||
Gain (loss) reclassified to results of operating due to the settlement of derivative contracts | -83 | -55 | -160 | -140 | ||||
Increase (decrease) in fair value related to the swap contract | -3 | -35 | -11 | -86 | ||||
Realized gains (losses) related to swap contract with unaffiliated parties | -82 | -119 | -215 | -427 | ||||
Fair value of Constellation fair value assets acquired | ' | 310 | ' | 310 | ||||
Other Investments [Member] | Fair Value Inputs Level 3 [Member] | ' | ' | ' | ' | ||||
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract] | ' | ' | ' | ' | ||||
Beginning balance | 11 | 17 | 17 | ' | ||||
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract] | ' | ' | ' | ' | ||||
Purchases | 0 | 0 | 2 | 17 | ||||
Sales | ' | ' | -8 | ' | ||||
Ending balance | 11 | 17 | 11 | 17 | ||||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract] | ' | ' | ' | ' | ||||
Fair value of Constellation fair value assets acquired | ' | 14 | ' | 14 | ||||
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | ' | ' | ' | ' | ||||
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract] | ' | ' | ' | ' | ||||
Beginning balance | 878 | 1,042 | 949 | 867 | ||||
Total realized / unrealized gains (losses) | ' | ' | ' | ' | ||||
Included in income | -32 | -112 | -6 | -109 | ||||
Included in other comprehensive income | 0 | -139 | -219 | -311 | ||||
Included in payable for Zion Station decommissioning | 0 | 1 | 1 | 0 | ||||
Included in noncurrent payables to affiliates | 1 | -2 | 8 | -2 | ||||
Change in collateral | -30 | -15 | 13 | -7 | ||||
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract] | ' | ' | ' | ' | ||||
Purchases | 41 | 18 | 151 | [9] | 437 | |||
Sales | -29 | 0 | -70 | -9 | ||||
Settlements | -3 | ' | -11 | ' | ||||
Transfers into Level 3 - (Asset) / Liability | 4 | 0 | 11 | -34 | ||||
Transfers out of Level 3 - (Asset) / Liability | -5 | 0 | -4 | -39 | ||||
Ending balance | 823 | 797 | 823 | 797 | ||||
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities | 51 | -77 | 149 | 1 | ||||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract] | ' | ' | ' | ' | ||||
Fair value of Constellation fair value assets acquired | 310 | ' | 310 | ' | ||||
Acquisition of marketable securities | 14 | ' | 14 | ' | ||||
Exelon Generation Co L L C [Member] | Nuclear Decommissioning Trust Fund Investment Level Three Asset [Member] | Fair Value Inputs Level 3 [Member] | ' | ' | ' | ' | ||||
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract] | ' | ' | ' | ' | ||||
Beginning balance | 240 | 54 | 183 | 13 | ||||
Total realized / unrealized gains (losses) | ' | ' | ' | ' | ||||
Included in income | 0 | ' | 2 | ' | ||||
Included in noncurrent payables to affiliates | 1 | -2 | 8 | -2 | ||||
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract] | ' | ' | ' | ' | ||||
Purchases | 23 | 14 | 90 | [9] | 55 | |||
Sales | -14 | ' | -27 | ' | ||||
Settlements | -3 | ' | -11 | ' | ||||
Ending balance | 245 | 70 | 245 | 70 | ||||
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities | 0 | ' | 1 | ' | ||||
Exelon Generation Co L L C [Member] | Pledged Assets For Zion Station Decommissioning [Member] | Fair Value Inputs Level 3 [Member] | ' | ' | ' | ' | ||||
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract] | ' | ' | ' | ' | ||||
Beginning balance | 111 | 59 | 89 | 37 | ||||
Total realized / unrealized gains (losses) | ' | ' | ' | ' | ||||
Included in payable for Zion Station decommissioning | 0 | 1 | 1 | 0 | ||||
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract] | ' | ' | ' | ' | ||||
Purchases | 10 | 4 | 43 | [9] | 36 | |||
Sales | -15 | 0 | -27 | -9 | ||||
Ending balance | 106 | 64 | 106 | 64 | ||||
Exelon Generation Co L L C [Member] | Derivative [Member] | Fair Value Inputs Level 3 [Member] | ' | ' | ' | ' | ||||
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract] | ' | ' | ' | ' | ||||
Beginning balance | 516 | 912 | 660 | 817 | ||||
Total realized / unrealized gains (losses) | ' | ' | ' | ' | ||||
Included in income | -32 | [10] | -112 | [11] | -8 | [12],[13] | -109 | [14],[2] |
Included in other comprehensive income | 0 | -139 | [5] | -219 | [12],[15] | -311 | [16],[5] | |
Change in collateral | -30 | -15 | 13 | -7 | ||||
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract] | ' | ' | ' | ' | ||||
Purchases | 8 | ' | 16 | 329 | [8] | |||
Sales | 0 | ' | -8 | ' | ||||
Transfers into Level 3 - (Asset) / Liability | 4 | 0 | 11 | -34 | ||||
Transfers out of Level 3 - (Asset) / Liability | -5 | 0 | -4 | -39 | ||||
Ending balance | 461 | 646 | 461 | 646 | ||||
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities | 51 | -77 | 148 | 1 | ||||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract] | ' | ' | ' | ' | ||||
Gain (loss) reclassified to results of operating due to the settlement of derivative contracts | -83 | -35 | -156 | -110 | ||||
Increase (decrease) in fair value related to the swap contract | 0 | -35 | 11 | 86 | ||||
Realized gains (losses) related to swap contract | 0 | -119 | -215 | -427 | ||||
Fair value of Constellation fair value assets acquired | ' | 310 | ' | 310 | ||||
Acquisition of marketable securities | ' | 14 | ' | 14 | ||||
Payment For Purchase Contracts | 10 | ' | 10 | ' | ||||
Exelon Generation Co L L C [Member] | Other Investments [Member] | Fair Value Inputs Level 3 [Member] | ' | ' | ' | ' | ||||
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract] | ' | ' | ' | ' | ||||
Beginning balance | 11 | 17 | 17 | ' | ||||
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract] | ' | ' | ' | ' | ||||
Purchases | 0 | 0 | 2 | 17 | ||||
Sales | ' | ' | -8 | ' | ||||
Ending balance | 11 | 17 | 11 | 17 | ||||
Commonwealth Edison Co [Member] | ' | ' | ' | ' | ||||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract] | ' | ' | ' | ' | ||||
Increase (decrease) in fair value related to the swap contract | ' | 7 | ' | 5 | ||||
Realized gains (losses) related to swap contract | ' | 88 | ' | 309 | ||||
Realized gains (losses) related to swap contract with unaffiliated parties | -1 | ' | -2 | ' | ||||
Increase (decrease) in fair value related to floating-to-fixed energy swap contracts | ' | -19 | ' | -54 | ||||
Commonwealth Edison Co [Member] | Fair Value Inputs Level 3 [Member] | ' | ' | ' | ' | ||||
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract] | ' | ' | ' | ' | ||||
Beginning balance | -85 | -617 | -293 | -800 | ||||
Total realized / unrealized gains (losses) | ' | ' | ' | ' | ||||
Included in regulatory assets | 37 | 195 | 171 | 378 | ||||
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract] | ' | ' | ' | ' | ||||
Ending balance | -122 | -422 | -122 | -422 | ||||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract] | ' | ' | ' | ' | ||||
Increase (decrease) in fair value related to the swap contract | ' | -35 | ' | 86 | ||||
Realized gains (losses) related to swap contract | ' | -119 | ' | -427 | ||||
Increase (decrease) in fair value related to floating-to-fixed energy swap contracts | ' | -40 | ' | ' | ||||
Commonwealth Edison Co [Member] | Derivative [Member] | Fair Value Inputs Level 3 [Member] | ' | ' | ' | ' | ||||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract] | ' | ' | ' | ' | ||||
Increase (decrease) in fair value related to the swap contract | 0 | ' | -11 | ' | ||||
Realized gains (losses) related to swap contract | 0 | ' | 215 | ' | ||||
Increase (decrease) in fair value related to floating-to-fixed energy swap contracts | ($37) | ' | $57 | ' | ||||
[1] | Includes the reclassification of $83 million and $160 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2013. | |||||||
[2] | Includes the reclassification of $55 million and $140 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2012, respectively. | |||||||
[3] | ) Includes the reclassification of $##D<gqtdreclasssettlement> million of realized losses due to the settlement of derivative contracts recorded in results of operations for the ##D<curmonth> months ended ##D<cyperiod>, respectively. | |||||||
[4] | Includes the reclassification of $##D<gpyreclasssettlment> million of realized losses due to the settlement of derivative contracts recorded in results of operations. | |||||||
[5] | B Excludes $35 million of decreases in fair value and $86 million of increases in fair value and $119 million and $427 million of realized losses due to settlements for the three and nine months ended September 30, 2012 of Generationbs financial swap contract with ComEd, which eliminates upon consolidation in Exelonbs Consolidated Financial Statements. | |||||||
[6] | Includes increases in fair value of $##D<gcomedfvpretaxytd> million and realized losses reclassified from OCI due to settlements of $##D<gcomedreclassytd> million associated with Generation's financial swap contract with ComEd for the ##D<curmonth> months ended ##D<cyperiod>, respectively. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements. | |||||||
[7] | Excludes decreases in fair value of $11 million and realized losses reclassified due to settlements of $215 million associated with Generationbs financial swap contract with ComEd for the nine months ended September 30, 2013. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements. | |||||||
[8] | Includes $310 million of fair value from contracts and $14 million of other investments acquired as a result of the merger. | |||||||
[9] | (c) Includes $##D<gfvacquiredq1> million of fair value from contracts and $##D<gfvothinvestq1> million of other investments acquired as a result of the merger. | |||||||
[10] | Includes the reclassification of $##D<gqtdreclasssettlement> million and $##D<gytdreclasssettlement> million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and ##D<curmonth> months ended ##D<cyperiod>, respectively | |||||||
[11] | ) B B B B B B B B Includes the reclassification of $35 million and $110 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2012, respectively. | |||||||
[12] | Includes $##D<gcomedfvpretaxqtd> million of decreases in fair value and $121 million of increases in fair value and realized losses due to settlements of $##D<gcomedreclassqtd> million and $308 million associated with Generation's financial swap contract with ComEd for the ##D<threemonth> and ##D<curmonth> months ended ##D<cyperiod>, respectively. This position was de-designated as a cash flow hedge prior to the merger date. All prospective changes in fair value and reclassifications of realized amounts are being recorded to income offset by the amortization of the frozen mark in OCI. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements | |||||||
[13] | (a) Includes the reclassification of $##D<gcyrclrellossq1> million of realized losses due to the settlement of derivative contracts recorded in results of operations. | |||||||
[14] | (a) Includes the reclassification of $##D<gpyreclasssettlmentq1> million of realized losses due to the settlement of derivative contracts recorded in results of operations. | |||||||
[15] | (b) Includes $##D<gcomedfvpretaxqtdq1> million of increases in fair value and $##D<gcomedreclassqtdq1> million of realized losses due to settlements during ##D<cyfiscal> of Generation's financial swap contract with ComEd, which eliminates upon consolidation in Exelon's Consolidated Financial Statements. | |||||||
[16] | (b) Includes $##D<gpycomedfvpretaxqtdq1> million of increases in fair value and $##D<gpycomedreclassqtdq1> million of realized losses due to settlements during ##D<pyfiscal> of Generation's financial swap contract with ComEd, which eliminates upon consolidation in Exelon's Consolidated Financial Statements. |
Fair_Value_of_Financial_Assets6
Fair Value of Financial Assets and Liabilities (Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings) (Details) (Fair Value Inputs Level 3 [Member], USD $) | 3 Months Ended | 9 Months Ended | ||||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | ||
Operating Revenue [Member] | ' | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items] | ' | ' | ' | ' | ||
Total gains (losses) included in income | ($39) | ($101) | ($61) | ($78) | ||
Change in the unrealized gains (losses) relating to assets and liabilities held | 42 | -43 | 81 | 82 | ||
Purchased Fuel and Electric [Member] | ' | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items] | ' | ' | ' | ' | ||
Total gains (losses) included in income | 7 | 4 | 60 | 0 | ||
Change in the unrealized gains (losses) relating to assets and liabilities held | 9 | 1 | 78 | -20 | ||
Other, net [Member] | ' | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items] | ' | ' | ' | ' | ||
Total gains (losses) included in income | 0 | [1] | ' | 2 | [1] | ' |
Change in the unrealized gains (losses) relating to assets and liabilities held | 0 | [1] | ' | 1 | [1] | ' |
Exelon Generation Co L L C [Member] | Operating Revenue [Member] | ' | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items] | ' | ' | ' | ' | ||
Total gains (losses) included in income | -39 | -116 | -67 | -109 | ||
Change in the unrealized gains (losses) relating to assets and liabilities held | 42 | -78 | 71 | 21 | ||
Exelon Generation Co L L C [Member] | Purchased Fuel and Electric [Member] | ' | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items] | ' | ' | ' | ' | ||
Total gains (losses) included in income | 7 | 4 | 59 | 0 | ||
Change in the unrealized gains (losses) relating to assets and liabilities held | 9 | 1 | 77 | -20 | ||
Exelon Generation Co L L C [Member] | Other, net [Member] | ' | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items] | ' | ' | ' | ' | ||
Total gains (losses) included in income | 0 | [2] | ' | 2 | [2] | ' |
Change in the unrealized gains (losses) relating to assets and liabilities held | $0 | [2] | ' | $1 | [2] | ' |
[1] | Other, net activity consists of realized and unrealized gains (losses) included in income for the NDT funds held by Generation. | |||||
[2] | B B B B B B B B 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 $) | 9 Months Ended | 12 Months Ended | ||
Sep. 30, 2013 | Dec. 31, 2012 | |||
Derivatives Fair Value [Line Items] | ' | ' | ||
Forward Power Basis | 1.96 | ' | ||
Forward Gas Basis | 0.18 | ' | ||
Derivatives Fair Value Footnotes [Abstract] | ' | ' | ||
Cash collateral excluded | 20,000,000 | ' | ||
Fair Value Inputs Level 3 [Member] | ' | ' | ||
Derivatives Fair Value Footnotes [Abstract] | ' | ' | ||
Cash collateral excluded | ' | 33,000,000 | ||
Fair Value Inputs Level 3 [Member] | Business Intersegment Transactions [Member] | Discounted Cash Flow [Member] | ' | ' | ||
Derivatives Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | ' | 226,000,000 | [1] | |
Fair Value Inputs Level 3 [Member] | Business Intersegment Transactions [Member] | Discounted Cash Flow [Member] | Minimum [Member] | ' | ' | ||
Fair Value Inputs [Abstract] | ' | ' | ||
Marketability Reserve | ' | 8.00% | [2] | |
Fair Value Inputs Level 3 [Member] | Business Intersegment Transactions [Member] | Discounted Cash Flow [Member] | Maximum [Member] | ' | ' | ||
Fair Value Inputs [Abstract] | ' | ' | ||
Marketability Reserve | ' | 9.00% | [2] | |
Exelon Generation Co L L C [Member] | ' | ' | ||
Derivatives Fair Value Footnotes [Abstract] | ' | ' | ||
Outstanding Commitments to invest | 192,000,000 | ' | ||
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Derivative [Member] | ' | ' | ||
Derivatives Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | 462,000,000 | [3] | 473,000,000 | [1] |
Derivatives Fair Value Footnotes [Abstract] | ' | ' | ||
Fair value swap contract current asset | ' | 226,000,000 | ||
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Derivative [Member] | Discounted Cash Flow [Member] | Minimum [Member] | ' | ' | ||
Fair Value Inputs [Abstract] | ' | ' | ||
Forward power price assets | 15,000,000 | 14,000,000 | [4] | |
Forward gas price assets | 3.51 | 3.26 | [4] | |
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Derivative [Member] | Discounted Cash Flow [Member] | Maximum [Member] | ' | ' | ||
Fair Value Inputs [Abstract] | ' | ' | ||
Forward power price assets | 103,000,000 | 79,000,000 | [4] | |
Forward gas price assets | 5.97 | 6.27 | [4] | |
Renewable factor | ' | 123.00% | ||
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Derivative [Member] | Option Model Valuation Technique [Member] | Minimum [Member] | ' | ' | ||
Fair Value Inputs [Abstract] | ' | ' | ||
Volatility percentage | 27.00% | 28.00% | [4] | |
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Derivative [Member] | Option Model Valuation Technique [Member] | Maximum [Member] | ' | ' | ||
Fair Value Inputs [Abstract] | ' | ' | ||
Volatility percentage | 107.00% | 132.00% | [4] | |
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Proprietary Trading [Member] | ' | ' | ||
Derivatives Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | ' | 6,000,000 | [1] | |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | -19,000,000 | [3] | ' | |
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Proprietary Trading [Member] | Discounted Cash Flow [Member] | Minimum [Member] | ' | ' | ||
Fair Value Inputs [Abstract] | ' | ' | ||
Forward power price assets | -14,000,000 | -15,000,000 | [4] | |
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Proprietary Trading [Member] | Discounted Cash Flow [Member] | Maximum [Member] | ' | ' | ||
Fair Value Inputs [Abstract] | ' | ' | ||
Forward power price assets | -103,000,000 | -106,000,000 | [4] | |
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Proprietary Trading [Member] | Option Model Valuation Technique [Member] | Minimum [Member] | ' | ' | ||
Fair Value Inputs [Abstract] | ' | ' | ||
Volatility percentage | 14.00% | 16.00% | [4] | |
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Proprietary Trading [Member] | Option Model Valuation Technique [Member] | Maximum [Member] | ' | ' | ||
Fair Value Inputs [Abstract] | ' | ' | ||
Volatility percentage | 28.00% | 48.00% | [4] | |
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Business Intersegment Transactions [Member] | ' | ' | ||
Derivatives Fair Value Footnotes [Abstract] | ' | ' | ||
Fair value swap contract current asset | 0 | ' | ||
Commonwealth Edison Co [Member] | Fair Value Inputs Level 3 [Member] | Derivative [Member] | ' | ' | ||
Derivatives Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | 122,000,000 | [3] | ' | |
Commonwealth Edison Co [Member] | Fair Value Inputs Level 3 [Member] | Derivative [Member] | Discounted Cash Flow [Member] | ' | ' | ||
Derivatives Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | ' | 67,000,000 | [1] | |
Commonwealth Edison Co [Member] | Fair Value Inputs Level 3 [Member] | Derivative [Member] | Discounted Cash Flow [Member] | Minimum [Member] | ' | ' | ||
Fair Value Inputs [Abstract] | ' | ' | ||
Marketability Reserve | 3.50% | 3.50% | ||
Forward heat rate | -8.00% | -8.00% | [5] | |
Renewable factor | 84.00% | 81.00% | ||
Commonwealth Edison Co [Member] | Fair Value Inputs Level 3 [Member] | Derivative [Member] | Discounted Cash Flow [Member] | Maximum [Member] | ' | ' | ||
Fair Value Inputs [Abstract] | ' | ' | ||
Marketability Reserve | 8.00% | 8.30% | ||
Forward heat rate | -9.00% | -9.50% | [5] | |
Renewable factor | 130.00% | ' | ||
Commonwealth Edison Co [Member] | Fair Value Inputs Level 3 [Member] | Business Intersegment Transactions [Member] | ' | ' | ||
Derivatives Fair Value Footnotes [Abstract] | ' | ' | ||
Fair value swap contract current liability | 0 | ' | ||
[1] | The fair values do not include cash collateral held on level three positions of $33 million as of December 31, 2012. | |||
[2] | Includes current assets for Generation and current liabilities for ComEd of $226 million, related to the fair value of the five-year financial swap contract between Generation and ComEd, which eliminates in consolidation. | |||
[3] | The fair values do not include cash collateral held on level three positions of $20 million as of September 30, 2013. | |||
[4] | B B B B B B B B B B B B B B B B The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions. | |||
[5] | 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 contractbs delivery. |
Derivative_Financial_Instrumen2
Derivative Financial Instruments (Commodity Price Risk) (Details) | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | |
GWh | GWh | GWh | GWh | |
Exelon Generation Co L L C [Member] | ' | ' | ' | ' |
Proprietary Trading Volumes [Abstract] | ' | ' | ' | ' |
Proprietary trading activities volume | 2,499 | 4,352 | 6,066 | 9,981 |
Exelon Generation Co L L C [Member] | Minimum [Member] | ' | ' | ' | ' |
Percent Of Expected Generation Being Hedged [Abstract] | ' | ' | ' | ' |
Expected generation hedged in next twelve months | ' | ' | 97.00% | ' |
Expected generation hedged in year two | ' | ' | 84.00% | ' |
Expected generation hedged in year three | ' | ' | 48.00% | ' |
Exelon Generation Co L L C [Member] | Maximum [Member] | ' | ' | ' | ' |
Percent Of Expected Generation Being Hedged [Abstract] | ' | ' | ' | ' |
Expected generation hedged in next twelve months | ' | ' | 100.00% | ' |
Expected generation hedged in year two | ' | ' | 87.00% | ' |
Expected generation hedged in year three | ' | ' | 51.00% | ' |
PECO Energy Co [Member] | ' | ' | ' | ' |
Percent Of Gas Purchases Being Hedged [Abstract] | ' | ' | ' | ' |
Estimated percentage of natural gas purchases hedged | ' | ' | 30.00% | ' |
Baltimore Gas and Electric Company [Member] | Minimum [Member] | ' | ' | ' | ' |
Percent Of Gas Purchases Being Hedged [Abstract] | ' | ' | ' | ' |
Estimated percentage of natural gas purchases hedged | ' | ' | 10.00% | ' |
Baltimore Gas and Electric Company [Member] | Maximum [Member] | ' | ' | ' | ' |
Percent Of Gas Purchases Being Hedged [Abstract] | ' | ' | ' | ' |
Estimated percentage of natural gas purchases hedged | ' | ' | 20.00% | ' |
Derivative_Financial_Instrumen3
Derivative Financial Instruments (Interest Rate Risk) (Details) (USD $) | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 12 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 9 Months Ended | 12 Months Ended | 3 Months Ended | 9 Months Ended | ||||||||||||||||||||||||||||||||||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | ||||
Fair Value Hedging [Member] | Fair Value Hedging [Member] | Fair Value Hedging [Member] | Antelope Valle [Member] | Designated as Hedging Instrument [Member] | Designated as Hedging Instrument [Member] | Designated as Hedging Instrument [Member] | Designated as Hedging Instrument [Member] | Designated as Hedging Instrument [Member] | Designated as Hedging Instrument [Member] | Designated as Hedging Instrument [Member] | Designated as Hedging Instrument [Member] | Derivative [Member] | Derivative [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Other Segment [Member] | Other Segment [Member] | ||||||||
Interest Rate Cash Flow Hedge Derivatives | Fair Value Hedging [Member] | Fair Value Hedging [Member] | Fair Value Hedging [Member] | Interest Rate Swap | Interest Rate Swap | Interest Rate Swap | Other Solar Projects [Member] | Interest Rate Swap | Fair Value Hedging [Member] | Fair Value Hedging [Member] | Fair Value Hedging [Member] | Antelope Valle [Member] | Antelope Valle [Member] | Designated as Hedging Instrument [Member] | Designated as Hedging Instrument [Member] | Designated as Hedging Instrument [Member] | Designated as Hedging Instrument [Member] | Designated as Hedging Instrument [Member] | Designated as Hedging Instrument [Member] | Designated as Hedging Instrument [Member] | Designated as Hedging Instrument [Member] | Designated as Hedging Instrument [Member] | Designated as Hedging Instrument [Member] | Designated as Hedging Instrument [Member] | Designated as Hedging Instrument [Member] | Designated as Hedging Instrument [Member] | Derivative [Member] | Derivative [Member] | Derivative [Member] | Derivative [Member] | Proprietary Trading [Member] | Proprietary Trading [Member] | Collateral And Netting [Member] | Collateral And Netting [Member] | Designated as Hedging Instrument [Member] | Designated as Hedging Instrument [Member] | ||||||||||||||||
Cash Flow Hedging [Member] | Fair Value Hedging [Member] | Fair Value Hedging [Member] | Fair Value Hedging [Member] | Interest Rate Cash Flow Hedge Derivatives | Designated as Hedging Instrument [Member] | Fair Value Hedging [Member] | Fair Value Hedging [Member] | Fair Value Hedging [Member] | Fair Value Hedging [Member] | Foreign Currency Fair Value Hedge Derivatives | Interest Rate Swap | Interest Rate Swap | Interest Rate Swap | Other Solar Projects [Member] | Interest Expense [Member] | Interest Expense [Member] | Antelope Valle [Member] | Interest Expense [Member] | ||||||||||||||||||||||||||||||||||
Cash Flow Hedging [Member] | Cash Flow Hedging [Member] | Fair Value Hedging [Member] | Fair Value Hedging [Member] | Fair Value Hedging [Member] | Fair Value Hedging [Member] | Antelope Valle [Member] | ||||||||||||||||||||||||||||||||||||||||||||||
Cost Of Capital Strategies [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Hypothetical increase in interest rates associated with variable-rate debt | 0.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Pre-tax net income impact associated with a hypothetical 10% increase in interest rates - exclusive upper bound | $1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Derivative Interest Rate Risk [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Mark-to-market derivative assets (current assets) | 2 | ' | 4 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | 4 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3 | 3 | ' | ' | 18 | [1] | 20 | [1] | -19 | [2] | 19 | [2] | ' | ' |
Mark-to-market derivative assets (noncurrent assets) | 46 | ' | 59 | ' | ' | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' | 23 | ' | 33 | ' | 46 | ' | ' | ' | ' | ' | 27 | 38 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5 | 8 | ' | ' | 17 | [1] | 32 | [1] | -16 | [2] | 32 | [2] | 13 | 13 |
Total mark-to-market derivative assets | 48 | ' | 63 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 35 | ' | 50 | ' | ' | ' | ' | ' | 27 | 38 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8 | 11 | ' | ' | 35 | [1] | 52 | [1] | -35 | [2] | 51 | [2] | 13 | 13 |
Mark-to-market derivative liabilities (current liabilities) | -2 | ' | -2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -2 | ' | -2 | ' | ' | ' | ' | ' | -1 | -1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -1 | -1 | ' | ' | -19 | [1] | -19 | [1] | 19 | [2] | -19 | [2] | ' | ' |
Mark-to-market derivative liabilities (noncurrent liabilities) | -14 | ' | -31 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -14 | ' | -31 | ' | ' | ' | ' | ' | -14 | -31 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | -16 | [1] | -32 | [1] | 16 | [2] | -32 | [2] | ' | ' |
Total mark-to-market derivative liabilities | -16 | ' | -33 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -16 | ' | -33 | ' | ' | ' | ' | ' | -15 | -32 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -1 | -1 | ' | ' | -35 | [1] | -51 | [1] | 35 | [2] | -51 | [2] | ' | ' |
Total mark-to-market derivative net assets (liabilities) | 32 | ' | 30 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 19 | ' | 17 | ' | ' | ' | ' | ' | 12 | 6 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7 | 10 | ' | ' | 0 | [1] | 1 | [1] | 0 | [2] | ' | 13 | 13 | |
Derivative, Gain (Loss) on Derivative, Net [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Gain on swaps/borrowings | ' | ' | ' | ' | ' | 2 | ' | ' | 4 | 1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Loss on swaps/borrowings | ' | ' | ' | -5 | -2 | ' | ' | ' | ' | ' | -2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | -1 | -3 | -6 | ' | ' | ' | ' | -4 | -1 | -13 | -3 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Interest Rate Risk - Fair Value Hedges [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Increase (Decrease) in Fair Value of Interest Rate Fair Value Hedging Instruments | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 40 | 49 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 27 | 38 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Interest rate swaps previously held by acquiree | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 550 | 550 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Notional amount of interest rate swaps acquired from merger | 150 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Fair value of interest rate swaps acquired from merger | 3 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Interest Rate Risk - Cash Flow Hedges [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Notional Amount of Pre-issuance Interest Rate Cash Flow Hedge Derivatives | ' | ' | ' | ' | ' | ' | ' | 213 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Pre-tax gain/loss on interest rate cash flow hedges | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -4 | -12 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
DOE loan guarantee | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 646 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
DOE interest rate swap | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 485 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Percentage of interest rate swap in relation to DOE guarantee | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 75 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Notional amount of interest rate swap DOE advance | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 328 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Percent of DOE loan advance offset | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 75.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Notional amount of remaining cash flow hedges | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 156 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Notional amounts on forward starting interest rate swaps | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 29 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 28 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Mark-to-market derivative liabilities | 218 | ' | 281 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 112 | ' | 232 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | 13 | ' | ' | ' | ' | ' | ' | ||||
Unrealized Gain (Loss) on Derivatives | 229 | 377 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 222 | 345 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Derivative, Notional Amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,100 | 1,100 | 650 | ' | ' | 1,250 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 38 | 134 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Deferred Gain on Derivatives | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 26 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Increase In Notional Amount Of Derivative Instruments | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $450 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
[1] | B B B B B B B B B B B B B B B B Generation enters into interest rate derivative contracts to economically hedge risk associated with theB interest rate component of commodity positions.B The characterization of the interest rate derivative contracts between the proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rate exposure.B Generation does not utilize 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 (Fair Value Measurments) (Details) (USD $) | 3 Months Ended | 6 Months Ended | 9 Months Ended | 12 Months Ended | ||||||||||||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Jun. 30, 2012 | Jun. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Dec. 31, 2011 | ||||||||
Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Ineffective portion recognized in income | ' | ' | ' | ' | $1 | ' | ' | ' | ||||||||
Footnotes To Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Net gain (loss) of reclassifications from accumulated OCI to net income related to settlements of block contracts | ' | ' | ' | ' | ' | 0 | ' | ' | ||||||||
Derivatives Fair Value [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Mark-to-market derivative assets | 730 | ' | ' | ' | 730 | ' | 938 | ' | ||||||||
Mark-to-market derivative assets (noncurrent assets) | 779 | ' | ' | ' | 779 | ' | 937 | ' | ||||||||
Mark-to-market derivative liabilities (current liabilities) | -126 | ' | ' | ' | -126 | ' | -352 | ' | ||||||||
Mark-to-market derivative liabilities (noncurrent liabilities) | -218 | ' | ' | ' | -218 | ' | -281 | ' | ||||||||
Other Derivatives Not Designated As Hedging Instruments [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Change in fair value | 180 | -91 | ' | ' | 217 | 98 | ' | ' | ||||||||
Reclassification to realized at settlement | 66 | 123 | ' | ' | 61 | 216 | ' | ' | ||||||||
Net mark-to-market gains (losses) | 246 | 32 | ' | ' | 278 | 314 | ' | ' | ||||||||
Operating Revenue [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Proprietary Trading Activities [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Change in fair value | 0 | -2 | ' | ' | 1 | 12 | ' | ' | ||||||||
Reclassification to realized at settlement | -40 | 25 | ' | ' | -36 | 57 | ' | ' | ||||||||
Net mark-to-market gains (losses) | -40 | 23 | ' | ' | -35 | 69 | ' | ' | ||||||||
Derivative [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Derivatives Fair Value [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Mark-to-market derivative assets | 728 | ' | ' | ' | 728 | ' | 934 | ' | ||||||||
Mark-to-market derivative assets (noncurrent assets) | 733 | ' | ' | ' | 733 | ' | 878 | ' | ||||||||
Total mark-to-market derivative assets | 1,461 | ' | ' | ' | 1,461 | ' | 1,812 | ' | ||||||||
Mark-to-market derivative liabilities (current liabilities) | -124 | ' | ' | ' | -124 | ' | -350 | ' | ||||||||
Mark-to-market derivative liabilities (noncurrent liabilities) | -204 | ' | ' | ' | -204 | ' | -250 | ' | ||||||||
Total mark-to-market derivative liabilities | -328 | ' | ' | ' | -328 | ' | -600 | ' | ||||||||
Total mark-to-market derivative net assets (liabilities) | 1,133 | ' | ' | ' | 1,133 | ' | 1,212 | ' | ||||||||
Reclassification out of Accumulated Other Comprehensive Income [Member] | Cash Flow Hedge reclassified from AOCI to net income | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Cash Flow Hedge Activity Impact [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Cash flow hedge activity impact on pre-tax net income based on reclassification adjustment from accumulated other comprehensive income | 84 | 145 | ' | ' | 324 | 548 | ' | ' | ||||||||
Total Cash Flow Hedges [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Accumulated OCI derivative gain - Beginning Balance | 245 | 547 | ' | 368 | 368 | 488 | 488 | ' | ||||||||
Effective portion of changes in fair value | 2 | [1] | 0 | [2] | ' | ' | 25 | [3] | 301 | [4] | ' | ' | ||||
Accumulated OCI derivative gain - Ending Balance | 199 | 459 | ' | ' | 199 | 459 | ' | ' | ||||||||
Footnotes To Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Net gains (losses) related to interest rate swaps and treasury rate locks | ' | ' | ' | ' | ' | -22 | ' | ' | ||||||||
Net gain (loss) related to effective portion of changes in fair value of treasury rate locks | 2 | 0 | ' | ' | -25 | ' | ' | ' | ||||||||
Total Cash Flow Hedges [Member] | Operating Revenue [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Ineffective portion recognized in income | ' | ' | ' | ' | ' | 3 | ' | ' | ||||||||
Total Cash Flow Hedges [Member] | Operating Revenue [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Cash Flow Hedge reclassified from AOCI to net income | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Reclassifications from accumulated OCI to net income | -48 | -88 | ' | ' | -194 | -333 | ' | ' | ||||||||
Exelon Generation Co L L C [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Reclassifications from accumulated OCI to net income | 3,871 | 3,558 | ' | ' | 10,729 | 9,276 | ' | ' | ||||||||
Cash Flow Hedge Activity Impact [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Net unrealized pre-tax gain (loss) on effective cash flow hedges | ' | ' | ' | ' | 1,928 | ' | ' | ' | ||||||||
Net unrealized pre-tax gain (loss) on effective cash flow hedges related to swap contract | ' | ' | ' | ' | 693 | ' | ' | ' | ||||||||
Expected reclassification from accumulated other comprehensive income to results of operations | ' | ' | ' | ' | 271 | ' | ' | ' | ||||||||
Expected reclassification from accumulated other comprehensive income to results of operations related to fair value of swap contracts | ' | ' | ' | ' | 0 | ' | ' | ' | ||||||||
Cash flow hedge activity impact on pre-tax net income based on reclassification adjustment from accumulated other comprehensive income | 84 | 283 | ' | ' | 543 | 1,005 | ' | ' | ||||||||
Change in cash flow hedge ineffectiveness | ' | ' | ' | ' | 0 | 5 | ' | ' | ||||||||
Cash flow hedge ineffectiveness adjustment to accumulated other comprehensive income | ' | 5 | ' | ' | ' | 5 | ' | ' | ||||||||
Derivatives Fair Value [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Mark-to-market derivative assets | 730 | ' | ' | ' | 730 | ' | 938 | ' | ||||||||
Mark-to-market derivative assets with affiliate (current assets) | 0 | ' | ' | ' | 0 | ' | 226 | ' | ||||||||
Mark-to-market derivative assets (noncurrent assets) | 766 | ' | ' | ' | 766 | ' | 924 | ' | ||||||||
Mark-to-market derivative liabilities (current liabilities) | -110 | ' | ' | ' | -110 | ' | -334 | ' | ||||||||
Mark-to-market derivative liabilities (noncurrent liabilities) | -112 | ' | ' | ' | -112 | ' | -232 | ' | ||||||||
Other Derivatives Not Designated As Hedging Instruments [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Change in fair value | 180 | -126 | ' | ' | 223 | 36 | ' | ' | ||||||||
Reclassification to realized at settlement | 66 | 142 | ' | ' | 48 | 245 | ' | ' | ||||||||
Net mark-to-market gains (losses) | 246 | 16 | ' | ' | 271 | 281 | ' | ' | ||||||||
Exelon Generation Co L L C [Member] | Operating Revenue [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Proprietary Trading Activities [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Change in fair value | 0 | -2 | ' | ' | 1 | 12 | ' | ' | ||||||||
Reclassification to realized at settlement | -40 | 25 | ' | ' | -36 | 57 | ' | ' | ||||||||
Net mark-to-market gains (losses) | -40 | 23 | ' | ' | -35 | 69 | ' | ' | ||||||||
Exelon Generation Co L L C [Member] | Operating Revenue [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Other Derivatives Not Designated As Hedging Instruments [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Change in fair value | 175 | -255 | ' | ' | 149 | -85 | ' | ' | ||||||||
Reclassification to realized at settlement | 41 | 20 | ' | ' | -15 | -81 | ' | ' | ||||||||
Net mark-to-market gains (losses) | 216 | -235 | ' | ' | 134 | -166 | ' | ' | ||||||||
Exelon Generation Co L L C [Member] | Operating Revenue [Member] | Consolidation, Eliminations [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Other Derivatives Not Designated As Hedging Instruments [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Change in fair value | 0 | 35 | ' | ' | -6 | 62 | ' | ' | ||||||||
Reclassification to realized at settlement | 0 | -19 | ' | ' | 13 | -29 | ' | ' | ||||||||
Net mark-to-market gains (losses) | 0 | 16 | ' | ' | 7 | 33 | ' | ' | ||||||||
Exelon Generation Co L L C [Member] | Purchased Power And Fuel [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Other Derivatives Not Designated As Hedging Instruments [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Change in fair value | 5 | 129 | ' | ' | 74 | 121 | ' | ' | ||||||||
Reclassification to realized at settlement | 25 | 122 | ' | ' | 63 | 326 | ' | ' | ||||||||
Net mark-to-market gains (losses) | 30 | 251 | ' | ' | 137 | 447 | ' | ' | ||||||||
Exelon Generation Co L L C [Member] | Derivative [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Derivatives Fair Value [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Mark-to-market derivative assets | 728 | [5] | ' | ' | ' | 728 | [5] | ' | 934 | [6] | ' | |||||
Mark-to-market derivative assets with affiliate (current assets) | ' | ' | ' | ' | ' | ' | 226 | [6] | ' | |||||||
Mark-to-market derivative assets (noncurrent assets) | 733 | [5] | ' | ' | ' | 733 | [5] | ' | 878 | [6] | ' | |||||
Total mark-to-market derivative assets | 1,461 | [5] | ' | ' | ' | 1,461 | [5] | ' | 2,038 | [6] | ' | |||||
Mark-to-market derivative liabilities (current liabilities) | -108 | [5] | ' | ' | ' | -108 | [5] | ' | -332 | [6] | ' | |||||
Mark-to-market derivative liabilities (noncurrent liabilities) | -98 | [5] | ' | ' | ' | -98 | [5] | ' | -201 | [6] | ' | |||||
Total mark-to-market derivative liabilities | -206 | [5] | ' | ' | ' | -206 | [5] | ' | -533 | [6] | ' | |||||
Total mark-to-market derivative net assets (liabilities) | 1,255 | [5] | ' | ' | ' | 1,255 | [5] | ' | 1,505 | [6] | ' | |||||
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Derivatives Fair Value [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Mark-to-market derivative assets | 2,244 | ' | ' | ' | 2,244 | ' | 2,883 | [7] | ' | |||||||
Mark-to-market derivative assets with affiliate (current assets) | ' | ' | ' | ' | ' | ' | 226 | [7] | ' | |||||||
Mark-to-market derivative assets (noncurrent assets) | 1,540 | ' | ' | ' | 1,540 | ' | 1,792 | [7] | ' | |||||||
Total mark-to-market derivative assets | 3,784 | ' | ' | ' | 3,784 | ' | 4,901 | [7] | ' | |||||||
Mark-to-market derivative liabilities (current liabilities) | -1,812 | ' | ' | ' | -1,812 | ' | -2,419 | [7] | ' | |||||||
Mark-to-market derivative liabilities (noncurrent liabilities) | -911 | ' | ' | ' | -911 | ' | -1,080 | [7] | ' | |||||||
Total mark-to-market derivative liabilities | -2,723 | ' | ' | ' | -2,723 | ' | -3,499 | [7] | ' | |||||||
Total mark-to-market derivative net assets (liabilities) | 1,061 | ' | ' | ' | 1,061 | ' | 1,402 | [7] | ' | |||||||
Footnotes To Derivative Instruments In Statement Of Financial Position Fair Value [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Current assets collateral offset | 86 | ' | ' | ' | 86 | ' | 113 | ' | ||||||||
Noncurrent assets collateral offset | 8 | ' | ' | ' | 8 | ' | 201 | ' | ||||||||
Current liabilities collateral offset | -235 | ' | ' | ' | -235 | ' | -214 | ' | ||||||||
Noncurrent liabilities collateral offset | -5 | ' | ' | ' | -5 | ' | -131 | ' | ||||||||
Total cash collateral received net of cash collateral posted | ' | ' | ' | ' | ' | ' | 31 | ' | ||||||||
Exelon Generation Co L L C [Member] | Cash Flow Hedging [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Footnotes To Derivative Instruments In Statement Of Financial Position Fair Value [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Fair value swap contract current asset | 0 | ' | ' | ' | 0 | ' | 226 | ' | ||||||||
Fair value swap contract noncurrent asset | ' | ' | ' | ' | ' | ' | 0 | ' | ||||||||
Noncurrent liability DOE interest rate swap | ' | ' | ' | ' | 23 | ' | 0 | ' | ||||||||
Exelon Generation Co L L C [Member] | Proprietary Trading [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Derivatives Fair Value [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Mark-to-market derivative assets | 1,577 | ' | ' | ' | 1,577 | ' | 2,469 | ' | ||||||||
Mark-to-market derivative assets (noncurrent assets) | 447 | ' | ' | ' | 447 | ' | 724 | ' | ||||||||
Total mark-to-market derivative assets | 2,024 | ' | ' | ' | 2,024 | ' | 3,193 | ' | ||||||||
Mark-to-market derivative liabilities (current liabilities) | -1,538 | ' | ' | ' | -1,538 | ' | -2,432 | ' | ||||||||
Mark-to-market derivative liabilities (noncurrent liabilities) | -438 | ' | ' | ' | -438 | ' | -689 | ' | ||||||||
Total mark-to-market derivative liabilities | -1,976 | ' | ' | ' | -1,976 | ' | -3,121 | ' | ||||||||
Total mark-to-market derivative net assets (liabilities) | 48 | ' | ' | ' | 48 | ' | 72 | ' | ||||||||
Exelon Generation Co L L C [Member] | Collateral And Netting [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Derivatives Fair Value [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Mark-to-market derivative assets | -3,093 | [8] | ' | ' | ' | -3,093 | [8] | ' | -4,418 | [8] | ' | |||||
Mark-to-market derivative assets (noncurrent assets) | -1,254 | [8] | ' | ' | ' | -1,254 | [8] | ' | -1,638 | [8] | ' | |||||
Total mark-to-market derivative assets | -4,347 | [8] | ' | ' | ' | -4,347 | [8] | ' | -6,056 | [8] | ' | |||||
Mark-to-market derivative liabilities (current liabilities) | 3,242 | [8] | ' | ' | ' | 3,242 | [8] | ' | 4,519 | [8] | ' | |||||
Mark-to-market derivative liabilities (noncurrent liabilities) | 1,251 | [8] | ' | ' | ' | 1,251 | [8] | ' | 1,568 | [8] | ' | |||||
Total mark-to-market derivative liabilities | 4,493 | [8] | ' | ' | ' | 4,493 | [8] | ' | 6,087 | [8] | ' | |||||
Total mark-to-market derivative net assets (liabilities) | 146 | [8] | ' | ' | ' | 146 | [8] | ' | 31 | [8] | ' | |||||
Footnotes To Derivative Instruments In Statement Of Financial Position Fair Value [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Total cash collateral received net of cash collateral posted | 146 | ' | ' | ' | 146 | ' | ' | ' | ||||||||
Exelon Generation Co L L C [Member] | Energy Related Hedges [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Accumulated OCI derivative gain - Beginning Balance | 255 | [9] | 923 | [10],[11] | ' | 532 | [12] | 532 | [12] | 925 | [13],[14] | 925 | [13],[14] | ' | ||
Effective portion of changes in fair value | ' | 0 | [15] | ' | ' | ' | 432 | [16] | ' | ' | ||||||
Accumulated OCI derivative gain - Ending Balance | 204 | [12],[9] | 752 | [10],[11],[13],[14] | 923 | [10],[11] | 255 | [9] | 204 | [12],[9] | 752 | [10],[11],[13],[14] | 532 | [12] | 925 | [13],[14] |
Footnotes To Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Unrealized gain (loss) related to fair value of swap contract | ' | 232 | 315 | ' | ' | 232 | 0 | 420 | ||||||||
Unrealized gain (loss) related to fair value of block contract | ' | 0 | ' | ' | ' | 0 | ' | 0 | ||||||||
Net gain (loss) related to effective portion of changes in fair value of swap contract | ' | ' | ' | ' | 0 | ' | 133 | ' | ||||||||
Net gain (loss) of reclassifications from accumulated OCI to net income related to the settlements of swap contract | ' | -83 | ' | ' | ' | ' | ' | ' | ||||||||
Net gains (losses) related to interest rate swaps and treasury rate locks | -11 | -22 | 22 | -11 | -11 | ' | -20 | -10 | ||||||||
Net gain (loss) related to effective portion of changes in fair value of treasury rate locks | ' | ' | ' | ' | ' | 88 | ' | ' | ||||||||
Exelon Generation Co L L C [Member] | Energy Related Hedges [Member] | Operating Revenue [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Ineffective portion recognized in income | ' | ' | ' | ' | ' | 3 | ' | ' | ||||||||
Footnotes To Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Net gain (loss) of reclassifications from accumulated OCI to net income related to the settlements of swap contract | 0 | ' | ' | ' | -133 | -276 | ' | ' | ||||||||
Exelon Generation Co L L C [Member] | Energy Related Hedges [Member] | Operating Revenue [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Cash Flow Hedge reclassified from AOCI to net income | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Reclassifications from accumulated OCI to net income | -51 | -171 | ' | ' | -328 | [17] | -608 | ' | ' | |||||||
Commonwealth Edison Co [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Derivatives Fair Value [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Mark-to-market derivative liabilities (current liabilities) | -16 | ' | ' | ' | -16 | ' | -18 | ' | ||||||||
Mark-to-market derivative liability with affiliate (current liability) | 0 | ' | ' | ' | 0 | ' | -226 | ' | ||||||||
Mark-to-market derivative liabilities (noncurrent liabilities) | -106 | ' | ' | ' | -106 | ' | -49 | ' | ||||||||
Commonwealth Edison Co [Member] | Derivative [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Derivatives Fair Value [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Mark-to-market derivative liabilities (current liabilities) | ' | ' | ' | ' | ' | ' | -18 | [7] | ' | |||||||
Mark-to-market derivative liability with affiliate (current liability) | ' | ' | ' | ' | ' | ' | -226 | [7] | ' | |||||||
Mark-to-market derivative liabilities (noncurrent liabilities) | ' | ' | ' | ' | ' | ' | -49 | [7] | ' | |||||||
Total mark-to-market derivative liabilities | ' | ' | ' | ' | ' | ' | -293 | [7] | ' | |||||||
Total mark-to-market derivative net assets (liabilities) | ' | ' | ' | ' | ' | ' | -293 | [7] | ' | |||||||
Commonwealth Edison Co [Member] | Designated as Hedging Instrument [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Derivatives Fair Value [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Mark-to-market derivative liabilities (current liabilities) | -16 | [18] | ' | ' | ' | -16 | [18] | ' | ' | ' | ||||||
Mark-to-market derivative liabilities (noncurrent liabilities) | -106 | [18] | ' | ' | ' | -106 | [18] | ' | ' | ' | ||||||
Total mark-to-market derivative liabilities | -122 | [18] | ' | ' | ' | -122 | [18] | ' | ' | ' | ||||||
Total mark-to-market derivative net assets (liabilities) | -122 | [18] | ' | ' | ' | -122 | [18] | ' | ' | ' | ||||||
Commonwealth Edison Co [Member] | Cash Flow Hedging [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Footnotes To Derivative Instruments In Statement Of Financial Position Fair Value [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Fair value swap contract current liability | 0 | ' | ' | ' | 0 | ' | 226 | ' | ||||||||
Fair value swap contract noncurrent liability | ' | ' | ' | ' | ' | ' | 0 | ' | ||||||||
Commonwealth Edison Co [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Derivatives Fair Value [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Mark-to-market derivative assets with affiliate (current assets) | ' | ' | ' | ' | ' | ' | -226 | [7] | ' | |||||||
Total mark-to-market derivative assets | ' | ' | ' | ' | ' | ' | -226 | [7] | ' | |||||||
Mark-to-market derivative liability with affiliate (current liability) | ' | ' | ' | ' | ' | ' | 226 | [7] | ' | |||||||
Total mark-to-market derivative liabilities | ' | ' | ' | ' | ' | ' | 226 | [7] | ' | |||||||
Baltimore Gas and Electric Company [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Reclassifications from accumulated OCI to net income | $735 | $716 | ' | ' | $2,261 | $2,023 | ' | ' | ||||||||
[1] | (b)B B B B B B B B Includes $2 million of gains, net of taxes, related to the effective portion of changes in fair value of interest rate swaps and treasury rate locks. | |||||||||||||||
[2] | Includes $0 million of losses, net of taxes, at Generation related to the effective portion of changes in fair value of interest rate swaps and treasury rate locks. | |||||||||||||||
[3] | Includes $25 million of losses, net of taxes, related to the effective portion of changes in fair value of interest rate swaps and treasury rate locks. | |||||||||||||||
[4] | Includes $12 million of losses, net of taxes, related to the effective portion of changes in fair value of interest rate swaps and treasury rate locks. | |||||||||||||||
[5] | Current and noncurrent assets are shown net of collateral of $86 million and $8 million, respectively, and current and noncurrent liabilities are shown net of collateral of $(235) million and $(5) million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $146 million at September 30, 2013. | |||||||||||||||
[6] | (c)B B B B B B B B Current and noncurrent assets are shown net of collateral of $113 million and $201 million, respectively, and current and noncurrent liabilities are shown net of collateral of $ (214) million and $ (131) million, respectively. The total cash collateral received, net of cash collateral posted and offset against mark-to-market assets and liabilities was $31 million at December 31, 2012. | |||||||||||||||
[7] | (a)B B B B B B B B Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $226 million related to the fair value of the five-year financial swap contract between Generation and ComEd, as described above. For Generation excludes $28 million of noncurrent liability relating to an interest rate swap in connection with a loan agreement to fund Antelope Valley as discussed above. | |||||||||||||||
[8] | 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.B 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. | |||||||||||||||
[9] | Excludes $11 million of losses, net of taxes, related to interest rate swaps and treasury rate locks as of September 30, 2013 and June 30, 2013. | |||||||||||||||
[10] | Includes $232 million and $315 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd as of September 30, 2012 and June 30, 2012, respectively. | |||||||||||||||
[11] | Excludes $22 million of losses and $22 million of gains, net of taxes, related to interest rate swaps and treasury rate locks for the three months ended September 30, 2012 and June 30, 2012 respectively. | |||||||||||||||
[12] | Excludes $11 million of losses and $20 million of losses, net of taxes, related to interest rate swaps and treasury locks as of September 30, 2013 and December 31, 2012, respectively. | |||||||||||||||
[13] | Includes $232 million and $420 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, as of September 30, 2012 and December 31, 2011. | |||||||||||||||
[14] | Excludes $22 million of losses and $10 million of losses, net of taxes, related to interest rate swaps and treasury rate locks for the nine months ended September 30, 2012 and year ended December 31, 2011, respectively. | |||||||||||||||
[15] | Includes $2 million of gains, net of taxes, related to the effective portion of changes in fair value of interest rate swaps and treasury rate locks. | |||||||||||||||
[16] | Includes $88 million of gains, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd through the date of de-designation prior to the merger. | |||||||||||||||
[17] | B B B B B B B B Includes $133 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, as of December 31, 2012. | |||||||||||||||
[18] | Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers. |
Derivative_Financial_Instrumen5
Derivative Financial Instruments (Credit Risk) (Details) (USD $) | Sep. 30, 2013 |
In Millions, unless otherwise specified | |
Exelon Generation Co L L C [Member] | ' |
Credit Risk [Abstract] | ' |
Financial institutions | $355 |
Investor-owned utilities, marketers and power producers | 743 |
Energy cooperative and municipalities | 916 |
Other | 52 |
Total | 2,066 |
Exelon Generation Co L L C [Member] | Commonwealth Edison Co Affiliate [Member] | ' |
Due From Related Parties [Abstract] | ' |
Net receivable from electric utility | 33 |
Exelon Generation Co L L C [Member] | Total Exposure Before Credit Collateral [Member] | ' |
Credit Risk [Abstract] | ' |
Investment grade | 1,767 |
Non-investment grade | 16 |
No external ratings - internally rated - investment grade | 472 |
No external ratings - internally rated - non-investment grade | 18 |
Total | 2,273 |
Exelon Generation Co L L C [Member] | Credit Collateral [Member] | ' |
Credit Risk [Abstract] | ' |
Investment grade | 191 |
Non-investment grade | 9 |
No external ratings - internally rated - investment grade | 6 |
No external ratings - internally rated - non-investment grade | 1 |
Total | 207 |
Exelon Generation Co L L C [Member] | Net Exposure [Member] | ' |
Credit Risk [Abstract] | ' |
Investment grade | 1,576 |
Non-investment grade | 7 |
No external ratings - internally rated - investment grade | 466 |
No external ratings - internally rated - non-investment grade | 17 |
Total | 2,066 |
Exelon Generation Co L L C [Member] | Number Of Counterparties Greater Than Ten Percent Of Net Exposure [Member] | ' |
Credit Risk [Abstract] | ' |
Investment grade | 1 |
Non-investment grade | 0 |
No external ratings - internally rated - investment grade | 1 |
No external ratings - internally rated - non-investment grade | 0 |
Total | 2 |
Exelon Generation Co L L C [Member] | Net Exposure Of Counterparties Greater Than Ten Percent Of Net Exposure [Member] | ' |
Credit Risk [Abstract] | ' |
Investment grade | 478 |
Non-investment grade | 0 |
No external ratings - internally rated - investment grade | 238 |
No external ratings - internally rated - non-investment grade | 0 |
Total | 716 |
PECO Energy Co [Member] | ' |
Natural Gas Supply And Management Agreement Credit Exposure [Abstract] | ' |
Credit exposure under natural gas supply and management agreements | 9 |
PECO Energy Co [Member] | PECO Energy Co Affiliate [Member] | ' |
Due From Related Parties [Abstract] | ' |
Net receivable from affiliated electric and gas utility | 30 |
Baltimore Gas and Electric Company [Member] | ' |
Natural Gas Supply And Management Agreement Credit Exposure [Abstract] | ' |
Credit exposure under off system sales | 1 |
Baltimore Gas and Electric Company [Member] | Baltimore Gas And Electric Company Affiliate [Member] | ' |
Due From Related Parties [Abstract] | ' |
Net receivable from affiliated electric and gas utility | $39 |
Derivative_Financial_Instrumen6
Derivative Financial Instruments (Collateral and Contingent-Related Features) (Details) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 | ||
In Millions, unless otherwise specified | ||||
Collateral And Contingent Related Features [Abstract] | ' | ' | ||
Aggregate fair value of derivatives with credit-risk-related contingent features | ($961) | [1] | ($1,849) | [1] |
Contractual right of offset related to derivative assets | 790 | [2] | 1,426 | [2] |
Net liability position after contractual right of offset | -171 | [3] | -423 | [3] |
Exelon Generation Co L L C [Member] | ' | ' | ||
Collateral And Contingent Related Features [Abstract] | ' | ' | ||
Incremental collateral for loss of investment grade credit rating | 1,800 | 2,000 | ||
Cash collateral held | 202 | 499 | ||
Cash collateral posted | 353 | 527 | ||
Letters of credit held | 32 | 45 | ||
Letters of credit posted | 326 | 563 | ||
Master Netting Arrangements [Abstract] | ' | ' | ||
Cash collateral received not offset against net derivative positions | 5 | 3 | ||
Commonwealth Edison Co [Member] | ' | ' | ||
Collateral And Contingent Related Features [Abstract] | ' | ' | ||
Cash collateral held | 19 | ' | ||
PECO Energy Co [Member] | ' | ' | ||
Collateral And Contingent Related Features [Abstract] | ' | ' | ||
Incremental collateral for loss of investment grade credit rating | 30 | ' | ||
Baltimore Gas and Electric Company [Member] | ' | ' | ||
Collateral And Contingent Related Features [Abstract] | ' | ' | ||
Incremental collateral for loss of investment grade credit rating | $41 | ' | ||
[1] | 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] | Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which a Registrant could potentially be required to post collateral. | |||
[3] | Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based. |
Debt_and_Credit_Agreements_Det
Debt and Credit Agreements (Details) (USD $) | Sep. 30, 2013 | Aug. 10, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | Aug. 10, 2013 | Jan. 23, 2013 | Dec. 31, 2012 | Oct. 18, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Jan. 23, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Mar. 14, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Oct. 18, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Aug. 30, 2013 | Aug. 10, 2013 | Dec. 31, 2012 | Oct. 18, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Oct. 15, 2013 | Sep. 30, 2013 | Aug. 10, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Oct. 18, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Oct. 01, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | |||||
Syndicated Revolver [Member] | Debt Continental Project [Member] | Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Designated as Hedging Instrument [Member] | Designated as Hedging Instrument [Member] | Designated as Hedging Instrument [Member] | Exelon Corporate [Member] | Exelon Corporate [Member] | Exelon Corporate [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | |||||||||
MW | Fair Value Hedging [Member] | Fair Value Hedging [Member] | Interest Rate Swap [Member] | Interest Rate Swap [Member] | Long Term Debt Retirements [Member] | Long Term Debt Retirements [Member] | SubsequentEventTypeMember [Member] | Syndicated Revolver [Member] | Syndicated Revolver [Member] | Bilateral Credit Facility [Member] | Bilateral Credit Facility [Member] | Letter of Credit [Member] | Designated as Hedging Instrument [Member] | Designated as Hedging Instrument [Member] | Designated as Hedging Instrument [Member] | Long Term Debt Issuances [Member] | Long Term Debt Issuances [Member] | Long Term Debt Issuances [Member] | Long Term Debt Issuances [Member] | Long Term Debt Issuances [Member] | Long Term Debt Issuances [Member] | Long Term Debt Issuances [Member] | Long Term Debt Issuances [Member] | Long Term Debt Issuances [Member] | Long Term Debt Retirements [Member] | Long Term Debt Retirements [Member] | Long Term Debt Retirements [Member] | Long Term Debt Retirements [Member] | Long Term Debt Retirements [Member] | Long Term Debt Retirements [Member] | Long Term Debt Retirements [Member] | Long Term Debt Retirements [Member] | Long Term Debt Retirements [Member] | Long Term Debt Retirements [Member] | Commercial Paper [Member] | SubsequentEventTypeMember [Member] | Syndicated Revolver [Member] | Long Term Debt Issuances [Member] | Long Term Debt Retirements [Member] | Long Term Debt Retirements [Member] | SubsequentEventTypeMember [Member] | Syndicated Revolver [Member] | Long Term Debt Issuances [Member] | Long Term Debt Issuances [Member] | Long Term Debt Issuances [Member] | Long Term Debt Retirements [Member] | Commercial Paper [Member] | SubsequentEventTypeMember [Member] | Syndicated Revolver [Member] | Long Term Debt Issuances [Member] | Long Term Debt Issuances [Member] | Long Term Debt Retirements [Member] | Long Term Debt Retirements [Member] | Long Term Debt Retirements [Member] | Long Term Debt Retirements [Member] | Long Term Debt Retirements [Member] | ||||||||||||||||||||||||||
Fair Value Hedging [Member] | Fair Value Hedging [Member] | Medium Term Notes, 7.3% June 1,2012 [Member] | Senior Notes [Member] | Continetal Wind [Member] | Continetal Wind [Member] | Foreign Exchange Contract [Member] | Interest Rate Swap [Member] | Interest Rate Swap [Member] | CEU Credit Agreement [Member] | Upstream Gas Property [Member] | Clean Horizons [Member] | Fixed Rate Debt [Member] | Fixed Rate Debt [Member] | Senior Notes [Member] | DOE Financing Project [Member] | DOE Financing Project [Member] | Energy Efficiency Project Financing [Member] | First Mortgage Bond Series 98, 7.6% April 1, 2032 [Member] | Kennett Square Capital Lease, 7.83%, September 20, 2020 [Member] | Armstrong Co Tax Exempt, 5% December 1,2042 [Member] | Upstream Gas Property [Member] | Clean Horizons [Member] | MEDCO Tax-Exempt Bonds [Member] | Capital Lease Obligations [Member] | Suboridanted Debentures [Member] | Solar Revolver [Member] | Solar Revolver [Member] | First Mortgage Bonds [Member] | First Mortgage Bonds [Member] | First Mortgage Bonds [Member] | Fixed Rate Debt [Member] | Fixed Rate Debt [Member] | Fixed Rate Debt [Member] | Fixed Rate Debt [Member] | Fixed Rate Debt [Member] | Senior Notes [Member] | Rate Stabilization Bonds, April 1, 2017 [Member] | Rate Stabilization Bonds, April 1, 2017 [Member] | Rate Stabilization Bonds, April 1, 2017 [Member] | Medium Term, Notes 6.73% 6.75% June 15, 2012 [Member] | Senior Notes [Member] | |||||||||||||||||||||||||||||||||||||||||
Senior Notes, 7.6% Due 2032 [Member] | Debt Continental Project [Member] | Senior Notes, 4.25% June 15, 2022 [Member] | Senior Notes, 5.6% June 15, 2042 [Member] | Fixed Rate Debt [Member] | Kennett Square Capital Lease, 7.83%, September 20, 2020 [Member] | Fixed Rate Debt [Member] | Fixed Rate Debt [Member] | Fixed Rate Debt [Member] | First And Refunding Mortgage Bonds, 2.375% September 15, 2022 [Member] | First And Refunding Mortgage Bonds 1200 October 15, 2016 [Member] | First And Refunding Mortgage Bonds 4800 October 15, 2043 [Member] | Fixed Rate Debt [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Continental Wind 6000 February 28, 2033 [Member] | First Mortgage Bonds 7.500% July1,2013 [Member] | Senior Notes 6.125% July1,2013 [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Credit Agreements [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Additional amounts available upon request under current credit facilities | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $500,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Basis points adders for prime-based borrowings | 0.0065 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.275 | ' | ' | 0.275 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.275 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.075 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Basis points adders for LIBOR-based borrowings | 0.0165 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1.275 | ' | ' | 1.275 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1.275 | ' | ' | ' | ' | ' | ' | ' | ' | 1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1.075 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Bilateral letters of credit | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 75,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Amount Of Aggregate Letters of Credit Available | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 500,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Revolver Under Amendment | ' | 500,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,300,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 600,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 600,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Accounts Receivable Agreement [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Short-term notes payable - accounts receivable agreement | 0 | ' | 210,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 210,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Accounts receivable, principal payment | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 210,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Gross accounts receivable pledged as collateral | 0 | ' | 289,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 289,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
AVSR Project Development Debt Agreement [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
DOE loan guarantee | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 646,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Generation letters of credit outstanding to support project | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 327,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Capital Lease Obligations [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Capital Lease term | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '20 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
CapitalLeaseObligationsIncurred | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
CapitalLeaseObligations | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Long-Term Debt [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Long-term debt to affiliate | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,528,000,000 | ' | ' | 2,007,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Non-Recourse Debt - MW | ' | ' | ' | ' | 667 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Non-Recourse Debt - Interest Rate Swap | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 350,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Total long-term debt | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 300,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Long-term debt | 17,583,000,000 | ' | 17,190,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 2,000,000 | 442,000,000 | 5,545,000,000 | ' | ' | 5,245,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 43,000,000 | ' | 38,000,000 | 523,000,000 | 788,000,000 | 613,000,000 | ' | 100,000,000 | 9,000,000 | 450,000,000 | 2,000,000 | 46,000,000 | 3,000,000 | 1,000,000 | 75,000,000 | 2,000,000 | 450,000,000 | [1] | 18,000,000 | 13,000,000 | 5,057,000,000 | ' | 5,315,000,000 | ' | ' | ' | 350,000,000 | 125,000,000 | 127,000,000 | 2,196,000,000 | ' | ' | 1,647,000,000 | ' | ' | 350,000,000 | 300,000,000 | 250,000,000 | ' | 1,746,000,000 | ' | 1,446,000,000 | ' | ' | ' | 250,000,000 | 300,000,000 | 34,000,000 | 33,000,000 | 31,000,000 | 110,000,000 | 400,000,000 | ||||
Long-term debt to financing trusts | 648,000,000 | ' | 648,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 206,000,000 | ' | 206,000,000 | ' | ' | ' | ' | ' | ' | 184,000,000 | ' | ' | 184,000,000 | ' | ' | ' | ' | ' | ' | 258,000,000 | ' | 258,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Interest rate on long-term debt | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7.30% | 7.60% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1.99% | ' | 2.50% | 4.25% | 5.60% | 6.00% | ' | ' | 4.40% | 6.15% | 7.83% | 5.00% | 2.27% | 2.56% | ' | 7.83% | 8.63% | [1] | ' | 2.49% | ' | ' | ' | ' | ' | ' | 4.60% | 7.63% | 7.50% | ' | ' | ' | ' | ' | ' | 2.38% | 1.20% | 4.80% | 5.60% | ' | ' | ' | ' | ' | ' | 2.80% | 3.35% | 5.72% | 5.72% | 5.68% | ' | 6.13% | ||||
Minimum interest rate on long-term debt | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2.21% | ' | ' | ' | ' | 2.54% | 2.33% | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1.93% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6.73% | ' | |||||
Maximum interest rate on long-term debt | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2.44% | ' | ' | ' | ' | 3.35% | 3.09% | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1.95% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6.75% | ' | |||||
Long Term Debt | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,000,000 | ' | ' | ' | ' | 204,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Gain from exchange offer | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 26,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Derivative, Gain on Derivative | ' | ' | ' | ' | ' | 2,000,000 | 4,000,000 | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
DebtInstrumentCollateralAmount | 1,800,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Footnotes To Long-Term Debt [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Capital Lease Obligations Noncurrent | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Notional amount of interest rate cash flow hedge derivatives | ' | ' | ' | ' | ' | ' | ' | ' | 1,100,000,000 | 650,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 38,000,000 | 134,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Line Of Credit Facility [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Aggregate bank commitments under unsecured revolving credit facilities | 8,400,000,000 | ' | ' | 500,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50,000,000 | 5,300,000,000 | [2] | 10,000,000 | 300,000,000 | 100,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 34,000,000 | 1,000,000,000 | [2] | ' | ' | ' | ' | ' | ' | ' | 34,000,000 | 600,000,000 | [2] | ' | ' | ' | ' | ' | ' | ' | ' | 5,000,000 | 600,000,000 | [2] | ' | ' | ' | ' | ' | ' | ' | |
Actual available capacity | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 131,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Footnotes To Line Of Credit Facility [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Credit facility agreements with minority and community banks | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 34,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 34,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Letters of credit | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 24,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 90,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 26,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 21,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Short Term Debt [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Commercial paper borrowings | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $153,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $40,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
[1] | Represents debt obligations assumed by Exelon as part of the merger on March 12, 2012 that became callable at face value on June 15, 2013. 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 as of December 31, 2012 included in long-term debt to affiliate on Generationbs Consolidated Balance Sheets and notes receivable from affiliates at Exelon Corporate, which are eliminated in consolidation on Exelonbs Consolidated Balance Sheets. The third-party debt obligations were reported in Long-term Debt on Exelonbs Consolidated Balance Sheets as of December 31, 2012. The debentures were redeemed and the intercompany loan agreements repaid on June 15, 2013. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[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 ComEdbs, PECObs and BGEbs service territories. These facilities expire on October 18, 2014 and are solely utilized to issue letters of credit. As of September 30, 2013, letters of credit issued under these agreements for Generation, ComEd, PECO and BGE totaled $24 million, $26 million, $21 million and $1 million, respectively. |
Income_Taxes_Details
Income Taxes (Details) (USD $) | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||||||||
Sep. 30, 2013 | Sep. 30, 2012 | Mar. 31, 2011 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2010 | Dec. 31, 2012 | Dec. 31, 1999 | |||||
Effective Income Tax Rate Reconciliation | ' | ' | ' | ' | ' | ' | ' | ' | ||||
U.S. Federal statutory rate | 35.00% | [1] | 35.00% | ' | 35.00% | [1] | 35.00% | ' | ' | ' | ||
Increase (decrease) due to: | ' | ' | ' | ' | ' | ' | ' | ' | ||||
State income taxes, net of Federal income tax benefit | 3.00% | [1] | 5.60% | [1] | ' | 5.30% | [1] | -4.70% | ' | ' | ' | |
Qualified nuclear decommissioning trust fund income (losses) | 3.50% | [1] | 7.80% | [1] | ' | 3.20% | [1] | 6.90% | ' | ' | ' | |
Domestic production activities deduction | 0.00% | [1] | 0.30% | [1] | ' | 0.00% | [1] | ' | ' | ' | ' | |
Tax exempt income | -0.20% | [1] | -0.20% | [1] | ' | -0.20% | [1] | -0.30% | ' | ' | ' | |
Nontaxable postretirement benefits | ' | 0.00% | [1] | ' | ' | ' | ' | ' | ' | |||
Health Care Reform Legislation | 0.10% | [1] | ' | ' | 0.10% | [1] | 0.20% | ' | ' | ' | ||
Amortization of investment tax credit | -1.50% | [1] | -4.80% | [1] | ' | -2.30% | [1] | -2.30% | ' | ' | ' | |
Plant basis differences | -0.80% | [1] | -4.70% | [1] | ' | -1.70% | [1] | -2.20% | ' | ' | ' | |
Production Tax Credits | -2.20% | [1] | -2.50% | ' | -2.40% | [1] | -2.60% | ' | ' | ' | ||
Fines and Penalties | ' | ' | ' | ' | 3.80% | ' | ' | ' | ||||
Merger Expenses | ' | -0.10% | ' | ' | 3.60% | [2] | ' | ' | ' | |||
Other | 0.50% | [1] | -1.20% | ' | 0.20% | [1] | -1.30% | ' | ' | ' | ||
Effective income tax rate | 37.40% | [1] | 35.20% | ' | 37.20% | [1] | 36.10% | ' | ' | ' | ||
Accounting for Uncertainty in Income Taxes [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Unrecognized tax benefits that if recognized would affect the effective tax rate | $2,220,000,000 | ' | ' | $2,220,000,000 | ' | ' | $1,024,000,000 | ' | ||||
1999 Sale of Fossil Generating Assets [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Deferred tax gain on sale of fossil generating assets | ' | ' | ' | ' | ' | ' | ' | 2,800,000,000 | ||||
Deferred tax gain under involuntary conversion provisions of the IRC | ' | ' | ' | ' | ' | ' | ' | 1,600,000,000 | ||||
Deferred tax gain under like-kind exchange provisions of the IRC | ' | ' | ' | ' | ' | ' | ' | 1,200,000,000 | ||||
IRS asserted penalties for understatement of tax | ' | ' | ' | 265,000,000 | ' | ' | ' | ' | ||||
Potential tax and interest from a successful IRS challenge of the like-kind exchange transaction position | 840,000,000 | ' | ' | 840,000,000 | ' | ' | ' | ' | ||||
IRS asserted penalties for understatement of tax related to like-kind exchange | ' | ' | ' | 87,000,000 | ' | ' | ' | ' | ||||
FIN 48 Tax Remeasurement [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||
FIN 48 Tax Remeasurement Interest Expense | ' | ' | 65,000,000 | ' | ' | ' | ' | ' | ||||
Tax Settlement [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Payment to IRS for open tax positions | ' | ' | ' | ' | ' | 302,000,000 | ' | ' | ||||
Income Tax Expense Benefit Continuing Operations [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Income Tax Expense (Benefit) | 439,000,000 | 161,000,000 | ' | 733,000,000 | 445,000,000 | ' | ' | ' | ||||
Exelon Generation Co L L C [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Effective Income Tax Rate Reconciliation | ' | ' | ' | ' | ' | ' | ' | ' | ||||
U.S. Federal statutory rate | 35.00% | [1] | 35.00% | ' | 35.00% | [1] | 35.00% | ' | ' | ' | ||
Increase (decrease) due to: | ' | ' | ' | ' | ' | ' | ' | ' | ||||
State income taxes, net of Federal income tax benefit | 2.60% | [1] | 5.90% | [1] | ' | 1.80% | [1] | 2.50% | ' | ' | ' | |
Qualified nuclear decommissioning trust fund income (losses) | 5.30% | [1] | 21.50% | [1] | ' | 5.10% | [1] | 10.90% | ' | ' | ' | |
Domestic production activities deduction | 0.00% | [1] | 0.80% | [1] | ' | 0.00% | [1] | ' | ' | ' | ' | |
Tax exempt income | -0.30% | [1] | -0.50% | [1] | ' | -0.30% | [1] | -0.50% | ' | ' | ' | |
Nontaxable postretirement benefits | ' | 0.00% | ' | ' | ' | ' | ' | ' | ||||
Health Care Reform Legislation | 0.00% | [1] | ' | ' | 0.00% | [1] | 0.00% | ' | ' | ' | ||
Amortization of investment tax credit | -2.10% | [1] | -13.00% | [1] | ' | -3.40% | [1] | -3.30% | ' | ' | ' | |
Plant basis differences | 0.00% | [1] | 0.00% | ' | 0.00% | [1] | 0.00% | ' | ' | ' | ||
Production Tax Credits | -3.30% | [1] | -7.40% | [1] | ' | -3.90% | [1] | -4.30% | ' | ' | ' | |
Fines and Penalties | ' | ' | ' | ' | 6.00% | ' | ' | ' | ||||
Other | 0.10% | [1] | 7.10% | [3] | ' | 1.10% | [1] | 0.80% | ' | ' | ' | |
Effective income tax rate | 37.30% | [1] | 49.40% | [3] | ' | 35.40% | [1] | 47.10% | ' | ' | ' | |
Accounting for Uncertainty in Income Taxes [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Unrecognized tax benefits that if recognized would affect the effective tax rate | 1,363,000,000 | ' | ' | 1,363,000,000 | ' | ' | 876,000,000 | ' | ||||
Information by nature of uncertainty related to unrecognized tax benefits | 160,000,000 | ' | ' | 160,000,000 | ' | ' | ' | ' | ||||
Increases based on tax positions prior to current year | ' | ' | ' | 446,000,000 | ' | ' | ' | ' | ||||
FIN 48 Tax Remeasurement [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||
FIN 48 Tax Remeasurement Current Tax Expense (Benefit) | ' | ' | 70,000,000 | ' | ' | ' | ' | ' | ||||
Reconciliation Of Unrecognized Tax Benefits Excluding Amounts Pertaining To Examined Tax Returns [Roll Forward] | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Increases based on tax positions prior to current year | ' | ' | ' | 446,000,000 | ' | ' | ' | ' | ||||
Income Tax Expense Benefit Continuing Operations [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Income Tax Expense (Benefit) | 288,000,000 | 85,000,000 | ' | 436,000,000 | 373,000,000 | ' | ' | ' | ||||
Commonwealth Edison Co [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Effective Income Tax Rate Reconciliation | ' | ' | ' | ' | ' | ' | ' | ' | ||||
U.S. Federal statutory rate | 35.00% | 35.00% | ' | 35.00% | 35.00% | ' | ' | ' | ||||
Increase (decrease) due to: | ' | ' | ' | ' | ' | ' | ' | ' | ||||
State income taxes, net of Federal income tax benefit | 5.40% | 5.00% | ' | 5.20% | 5.40% | ' | ' | ' | ||||
Qualified nuclear decommissioning trust fund income (losses) | 0.00% | 0.00% | ' | 0.00% | 0.00% | ' | ' | ' | ||||
Domestic production activities deduction | 0.00% | 0.00% | ' | 0.00% | ' | ' | ' | ' | ||||
Tax exempt income | 0.00% | ' | ' | 0.00% | 0.00% | ' | ' | ' | ||||
Nontaxable postretirement benefits | ' | 0.60% | ' | ' | ' | ' | ' | ' | ||||
Health Care Reform Legislation | 0.40% | ' | ' | 0.90% | 0.60% | ' | ' | ' | ||||
Amortization of investment tax credit | -0.40% | -0.50% | ' | -0.80% | -0.50% | ' | ' | ' | ||||
Plant basis differences | -0.40% | -0.50% | ' | -1.20% | -0.20% | ' | ' | ' | ||||
Production Tax Credits | 0.00% | 0.00% | ' | 0.00% | 0.00% | ' | ' | ' | ||||
Other | 0.30% | 0.00% | [3] | ' | 0.80% | 0.20% | ' | ' | ' | |||
Effective income tax rate | 40.30% | 39.60% | ' | 39.90% | 40.50% | ' | ' | ' | ||||
Accounting for Uncertainty in Income Taxes [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Unrecognized tax benefits that if recognized would affect the effective tax rate | 331,000,000 | ' | ' | 331,000,000 | ' | ' | 67,000,000 | ' | ||||
1999 Sale of Fossil Generating Assets [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||
IRS asserted penalties for understatement of tax | ' | ' | ' | 170,000,000 | ' | ' | ' | ' | ||||
Potential tax and interest from a successful IRS challenge of the like-kind exchange transaction position | 305,000,000 | ' | ' | 305,000,000 | ' | ' | ' | ' | ||||
Status Of Like Kind Exchange Position [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Receivable from Exelon intercompany money pool | 172,000,000 | ' | ' | 172,000,000 | ' | ' | ' | ' | ||||
FIN 48 Tax Remeasurement [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||
FIN 48 Tax Remeasurement Interest Expense | ' | ' | 36,000,000 | ' | ' | ' | ' | ' | ||||
FIN 48 Tax Remeasurement Current Tax Expense (Benefit) | ' | ' | 70,000,000 | ' | ' | ' | ' | ' | ||||
Income Tax Expense Benefit Continuing Operations [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Income Tax Expense (Benefit) | 85,000,000 | 59,000,000 | ' | 93,000,000 | 149,000,000 | ' | ' | ' | ||||
PECO Energy Co [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Effective Income Tax Rate Reconciliation | ' | ' | ' | ' | ' | ' | ' | ' | ||||
U.S. Federal statutory rate | 35.00% | 35.00% | ' | 35.00% | 35.00% | ' | ' | ' | ||||
Increase (decrease) due to: | ' | ' | ' | ' | ' | ' | ' | ' | ||||
State income taxes, net of Federal income tax benefit | -0.30% | 3.00% | ' | 1.90% | 3.20% | ' | ' | ' | ||||
Qualified nuclear decommissioning trust fund income (losses) | 0.00% | 0.00% | ' | 0.00% | 0.00% | ' | ' | ' | ||||
Domestic production activities deduction | 0.00% | 0.00% | ' | 0.00% | ' | ' | ' | ' | ||||
Tax exempt income | 0.00% | 0.00% | ' | 0.00% | 0.00% | ' | ' | ' | ||||
Nontaxable postretirement benefits | ' | 0.00% | ' | ' | ' | ' | ' | ' | ||||
Health Care Reform Legislation | 0.00% | ' | ' | 0.00% | 0.00% | ' | ' | ' | ||||
Amortization of investment tax credit | -0.10% | -0.30% | ' | -0.10% | -0.30% | ' | ' | ' | ||||
Plant basis differences | -6.90% | -21.00% | ' | -7.30% | -9.70% | ' | ' | ' | ||||
Production Tax Credits | 0.00% | 0.00% | ' | 0.00% | 0.00% | ' | ' | ' | ||||
Other | -0.10% | 0.20% | ' | 0.00% | 0.00% | ' | ' | ' | ||||
Effective income tax rate | 27.60% | 16.90% | ' | 29.50% | 28.20% | ' | ' | ' | ||||
Accounting for Uncertainty in Income Taxes [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Unrecognized tax benefits that if recognized would affect the effective tax rate | 44,000,000 | ' | ' | 44,000,000 | ' | ' | 44,000,000 | ' | ||||
Status Of Like Kind Exchange Position [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Receivable from Exelon intercompany money pool | 1,000,000 | ' | ' | 1,000,000 | ' | ' | ' | ' | ||||
FIN 48 Tax Remeasurement [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||
FIN 48 Tax Remeasurement Interest Expense | ' | ' | 22,000,000 | ' | ' | ' | ' | ' | ||||
Income Tax Expense Benefit Continuing Operations [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Income Tax Expense (Benefit) | 35,000,000 | 25,000,000 | ' | 122,000,000 | 118,000,000 | ' | ' | ' | ||||
Baltimore Gas and Electric Company [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Effective Income Tax Rate Reconciliation | ' | ' | ' | ' | ' | ' | ' | ' | ||||
U.S. Federal statutory rate | 35.00% | 0.00% | ' | 35.00% | 35.00% | [4] | ' | ' | ' | |||
Increase (decrease) due to: | ' | ' | ' | ' | ' | ' | ' | ' | ||||
State income taxes, net of Federal income tax benefit | 5.60% | 0.00% | ' | 5.60% | 2.30% | [4] | ' | ' | ' | |||
Qualified nuclear decommissioning trust fund income (losses) | 0.00% | 0.00% | ' | 0.00% | 0.00% | [4] | ' | ' | ' | |||
Domestic production activities deduction | 0.00% | 0.00% | ' | 0.00% | ' | ' | ' | ' | ||||
Tax exempt income | 0.00% | 0.00% | ' | 0.00% | 0.00% | [4] | ' | ' | ' | |||
Health Care Reform Legislation | 0.20% | 0.00% | ' | 0.20% | -4.60% | [4] | ' | ' | ' | |||
Amortization of investment tax credit | -0.30% | 0.00% | ' | -0.30% | 2.90% | ' | ' | ' | ||||
Plant basis differences | 0.10% | 0.00% | ' | -0.40% | 7.20% | [4] | ' | ' | ' | |||
Production Tax Credits | 0.00% | 0.00% | ' | 0.00% | 0.00% | ' | ' | ' | ||||
FIN 48 | ' | ' | ' | ' | -14.00% | [2] | ' | ' | ' | |||
Other | -0.20% | ' | ' | 0.00% | 4.50% | [4] | ' | ' | ' | |||
Effective income tax rate | 40.40% | 0.00% | ' | 40.10% | 33.30% | ' | ' | ' | ||||
Income Tax Expense Benefit Continuing Operations [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Income Tax Expense (Benefit) | $36,000,000 | $0 | ' | $107,000,000 | ($7,000,000) | ' | ' | ' | ||||
[1] | (a) Exelon activity for the three and nine months ended September 30, 2012 includes the results of Constellation and BGE for March 12, 2012 - September 30, 2012. Generation activity for the three and nine months ended September 30, 2012 includes the results of Constellation for March 12, 2012 - September 30, 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] | For the three months ended September 30, 2012, Generationbs effective tax rate was affected by the resolution of uncertain Federal tax positions (5.3%), the finalization of prior year tax return calculations 4.2%, changes in the forecasted activity attributable to noncontrolling interests 4.1%, and other 4.1%. | |||||||||||
[4] | BGE activity represents the activity for the three and nine months ended September 30, 2012. BGE activity for the three months ended September 30, 2012 resulted in zero pre-tax income and zero income taxes. BGE recognized a loss before income taxes for the nine months ended September 30, 2012. As a result, positive percentages represent an income tax benefit for BGE for the nine months ended September 30, 2012. |
Asset_Retirement_Obligation_De
Asset Retirement Obligation (Details) (USD $) | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||||||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | |||||
Nuclear Decommissioning Asset Retirement Obligations [Abstract] | ' | ' | ' | ' | ' | |||||
Increase in estimated cash flows associated with Zion Station decommissioning | ' | ' | $0 | ' | ' | |||||
Zion Station Decommissioning [Abstract] | ' | ' | ' | ' | ' | |||||
Zion Station spent nuclear fuel obligation | 81 | ' | 81 | ' | ' | |||||
Nuclear Decommissioning Trust Fund Investments [Abstract] | ' | ' | ' | ' | ' | |||||
Shortfall of decommissioning funds with recourse | 50 | ' | 50 | ' | ' | |||||
Percent of additional decommissioning shortfall with recourse | 5.00% | ' | 5.00% | ' | ' | |||||
NDT fund investments | 7,776 | ' | 7,776 | ' | 7,248 | |||||
NRC Minimum Funding Requirements [Abstract] | ' | ' | ' | ' | ' | |||||
Additional NRC funding assurance parent guarantees | ' | ' | ' | ' | 115 | |||||
Nuclear Decommissioning Obligation [Line Items] | ' | ' | ' | ' | ' | |||||
Pledged assets for Zion Station decommissioning | 486 | ' | 486 | ' | 614 | |||||
Total payable to ZionSolutions | 443 | [1] | ' | 443 | [1] | ' | 564 | [1] | ||
Current payable to ZionSolutions | 104 | [2] | ' | 104 | [2] | ' | 132 | [2] | ||
Zion Station decommissioning costs withdrawn | ' | ' | 458 | [3] | ' | 335 | [3] | |||
Unrealized Losses On Nuclear Decommissioning Trust Fund Investment [Line Items] | ' | ' | ' | ' | ' | |||||
Net unrealized gains (losses) on decommissioning trust funds - Regulatory Agreement Units | 103 | [4] | 202 | [4] | 196 | [4] | 352 | [4] | ' | |
Net unrealized gains (losses) on decommissioning trust funds - Non-Regulatory Agreement Units | 46 | [5],[6] | 71 | [5],[6] | 70 | [5],[6] | 101 | [5],[6] | ' | |
Footnotes To Unrealized Gains Losses On NDT Funds [Abstract] | ' | ' | ' | ' | ' | |||||
Gains on Zion Station Pledged Assets | 9 | 22 | 5 | 60 | ' | |||||
Nuclear Decommissioning Asset Retirement Obligation [Member] | ' | ' | ' | ' | ' | |||||
Asset Retirement Obligation Roll Forward Analysis [Roll Forward] | ' | ' | ' | ' | ' | |||||
ARO beginning balance | ' | ' | 4,741 | [7] | ' | ' | ||||
Accretion expense | ' | ' | 194 | ' | ' | |||||
Costs incurred to decommission retired plants | ' | ' | -2 | ' | ' | |||||
ARO ending balance | 4,792 | [7] | ' | 4,792 | [7] | ' | ' | |||
Footnotes To Asset Retirement Obligation [Abstract] | ' | ' | ' | ' | ' | |||||
Current Portion of ARO | 10 | ' | 10 | ' | 10 | |||||
Exelon Generation Co L L C [Member] | ' | ' | ' | ' | ' | |||||
Nuclear Decommissioning Asset Retirement Obligations [Abstract] | ' | ' | ' | ' | ' | |||||
Increase in estimated cash flows associated with Zion Station decommissioning | ' | ' | 0 | ' | ' | |||||
Zion Station Decommissioning [Abstract] | ' | ' | ' | ' | ' | |||||
Zion Station spent nuclear fuel obligation | 81 | ' | 81 | ' | ' | |||||
Nuclear Decommissioning Trust Fund Investments [Abstract] | ' | ' | ' | ' | ' | |||||
Shortfall of decommissioning funds with recourse | 50 | ' | 50 | ' | ' | |||||
Percent of additional decommissioning shortfall with recourse | 5.00% | ' | 5.00% | ' | ' | |||||
NDT fund investments | 7,776 | ' | 7,776 | ' | 7,248 | |||||
NRC Minimum Funding Requirements [Abstract] | ' | ' | ' | ' | ' | |||||
Additional NRC funding assurance parent guarantees | ' | ' | ' | ' | 115 | |||||
Nuclear Decommissioning Obligation [Line Items] | ' | ' | ' | ' | ' | |||||
Pledged assets for Zion Station decommissioning | 486 | ' | 486 | ' | 614 | |||||
Total payable to ZionSolutions | 443 | [1] | ' | 443 | [1] | ' | 564 | [1] | ||
Current payable to ZionSolutions | 104 | [2] | ' | 104 | [2] | ' | 132 | [2] | ||
Zion Station decommissioning costs withdrawn | ' | ' | 458 | [3] | ' | 335 | [3] | |||
Unrealized Losses On Nuclear Decommissioning Trust Fund Investment [Line Items] | ' | ' | ' | ' | ' | |||||
Net unrealized gains (losses) on decommissioning trust funds - Regulatory Agreement Units | 103 | [4] | 202 | [4] | 196 | [4] | 352 | [4] | ' | |
Net unrealized gains (losses) on decommissioning trust funds - Non-Regulatory Agreement Units | 46 | [5],[6] | 71 | [5],[6] | 70 | [5],[6] | 101 | [5],[6] | ' | |
Footnotes To Unrealized Gains Losses On NDT Funds [Abstract] | ' | ' | ' | ' | ' | |||||
Gains on Zion Station Pledged Assets | 9 | 22 | 5 | 60 | ' | |||||
Exelon Generation Co L L C [Member] | Nuclear Decommissioning Asset Retirement Obligation [Member] | ' | ' | ' | ' | ' | |||||
Asset Retirement Obligation Roll Forward Analysis [Roll Forward] | ' | ' | ' | ' | ' | |||||
ARO beginning balance | ' | ' | 4,741 | [7] | ' | ' | ||||
Accretion expense | ' | ' | 194 | ' | ' | |||||
Costs incurred to decommission retired plants | ' | ' | -2 | ' | ' | |||||
ARO ending balance | 4,792 | [7] | ' | 4,792 | [7] | ' | ' | |||
Footnotes To Asset Retirement Obligation [Abstract] | ' | ' | ' | ' | ' | |||||
Current Portion of ARO | $10 | ' | $10 | ' | $10 | |||||
[1] | Excludes a liability recorded within Exelonbs and Generationbs Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT Funds. The NDT Funds will be utilized to satisfy the tax obligations as gains and losses are realized. | |||||||||
[2] | Included in Other current liabilities within Exelonbs and Generationbs Consolidated Balance Sheets. | |||||||||
[3] | Cumulative withdrawals since September 1, 2010. | |||||||||
[4] | 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. | |||||||||
[5] | Net unrealized gains related to Generation's NDT funds associated with Non-Regulatory Agreement Units are included within Other, net in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. | |||||||||
[6] | Excludes $9 million of net unrealized losses and $22 million of net unrealized gains related to the Zion Station pledged assets for the three months ended September 30, 2013 and 2012, respectively, and $5 million of net unrealized losses and $60 million of net unrealized gains related to the Zion Station pledged assets for the nine months ended September 30, 2013 and 2012, respectively. Net unrealized gains (losses) related to Zion Station pledged assets are included in the Payable for Zion Station decommissioning on Exelon's and Generation's Consolidated Balance Sheets. | |||||||||
[7] | Includes $10 million as the current portion of the ARO at September 30, 2013 and December 31, 2012, respectively, which is included in Other current liabilities on Exelon's and Generation's Consolidated Balance Sheets. |
Nuclear_Decommissioning_Detail
Nuclear Decommissioning (Details) (USD $) | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||||||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | |||||
Nuclear Decommissioning Asset Retirement Obligations [Abstract] | ' | ' | ' | ' | ' | |||||
Increase in estimated cash flows associated with Zion Station decommissioning | ' | ' | $0 | ' | ' | |||||
Nuclear Decommissioning Trust Fund Investments [Abstract] | ' | ' | ' | ' | ' | |||||
NDT fund investments | 7,776 | ' | 7,776 | ' | 7,248 | |||||
Current annual recovery of decommissioning costs | ' | ' | 24 | ' | ' | |||||
Shortfall of decommissioning funds with recourse | 50 | ' | 50 | ' | ' | |||||
Decommissioning Shortfall Percentage | 5.00% | ' | 5.00% | ' | ' | |||||
Zion Station Decommissioning [Abstract] | ' | ' | ' | ' | ' | |||||
Zion Station spent nuclear fuel obligation | 81 | ' | 81 | ' | ' | |||||
Pledged assets for Zion Station decommissioning | 486 | ' | 486 | ' | 614 | |||||
Total payable to ZionSolutions | 443 | [1] | ' | 443 | [1] | ' | 564 | [1] | ||
Current payable to ZionSolutions | 104 | [2] | ' | 104 | [2] | ' | 132 | [2] | ||
Zion Station decommissioning costs withdrawn | ' | ' | 458 | [3] | ' | 335 | [3] | |||
NRC Minimum Funding Requirements [Abstract] | ' | ' | ' | ' | ' | |||||
Additional NRC funding assurance parent guarantees | ' | ' | ' | ' | 115 | |||||
Unrealized Losses On Nuclear Decommissioning Trust Fund Investment [Line Items] | ' | ' | ' | ' | ' | |||||
Net unrealized gains (losses) on decommissioning trust funds - Regulatory Agreement Units | 103 | [4] | 202 | [4] | 196 | [4] | 352 | [4] | ' | |
Net unrealized gains (losses) on decommissioning trust funds - Non-Regulatory Agreement Units | 46 | [5],[6] | 71 | [5],[6] | 70 | [5],[6] | 101 | [5],[6] | ' | |
Footnotes To Unrealized Gains Losses On NDT Funds [Abstract] | ' | ' | ' | ' | ' | |||||
Gains on Zion Station Pledged Assets | 9 | 22 | 5 | 60 | ' | |||||
Nuclear Decommissioning Asset Retirement Obligation [Member] | ' | ' | ' | ' | ' | |||||
Asset Retirement Obligation Roll Forward Analysis [Roll Forward] | ' | ' | ' | ' | ' | |||||
ARO beginning balance | ' | ' | 4,741 | [7] | ' | ' | ||||
Accretion expense | ' | ' | 194 | ' | ' | |||||
Costs incurred to decommission retired plants | ' | ' | -2 | ' | ' | |||||
ARO ending balance | 4,792 | [7] | ' | 4,792 | [7] | ' | ' | |||
Footnotes To Asset Retirement Obligation [Abstract] | ' | ' | ' | ' | ' | |||||
Current Portion of ARO | 10 | ' | 10 | ' | 10 | |||||
Exelon Generation Co L L C [Member] | ' | ' | ' | ' | ' | |||||
Nuclear Decommissioning Asset Retirement Obligations [Abstract] | ' | ' | ' | ' | ' | |||||
Increase in estimated cash flows associated with Zion Station decommissioning | ' | ' | 0 | ' | ' | |||||
Nuclear Decommissioning Trust Fund Investments [Abstract] | ' | ' | ' | ' | ' | |||||
NDT fund investments | 7,776 | ' | 7,776 | ' | 7,248 | |||||
Shortfall of decommissioning funds with recourse | 50 | ' | 50 | ' | ' | |||||
Decommissioning Shortfall Percentage | 5.00% | ' | 5.00% | ' | ' | |||||
Zion Station Decommissioning [Abstract] | ' | ' | ' | ' | ' | |||||
Zion Station spent nuclear fuel obligation | 81 | ' | 81 | ' | ' | |||||
Pledged assets for Zion Station decommissioning | 486 | ' | 486 | ' | 614 | |||||
Total payable to ZionSolutions | 443 | [1] | ' | 443 | [1] | ' | 564 | [1] | ||
Current payable to ZionSolutions | 104 | [2] | ' | 104 | [2] | ' | 132 | [2] | ||
Zion Station decommissioning costs withdrawn | ' | ' | 458 | [3] | ' | 335 | [3] | |||
NRC Minimum Funding Requirements [Abstract] | ' | ' | ' | ' | ' | |||||
Additional NRC funding assurance parent guarantees | ' | ' | ' | ' | 115 | |||||
Unrealized Losses On Nuclear Decommissioning Trust Fund Investment [Line Items] | ' | ' | ' | ' | ' | |||||
Net unrealized gains (losses) on decommissioning trust funds - Regulatory Agreement Units | 103 | [4] | 202 | [4] | 196 | [4] | 352 | [4] | ' | |
Net unrealized gains (losses) on decommissioning trust funds - Non-Regulatory Agreement Units | 46 | [5],[6] | 71 | [5],[6] | 70 | [5],[6] | 101 | [5],[6] | ' | |
Footnotes To Unrealized Gains Losses On NDT Funds [Abstract] | ' | ' | ' | ' | ' | |||||
Gains on Zion Station Pledged Assets | 9 | 22 | 5 | 60 | ' | |||||
Exelon Generation Co L L C [Member] | Nuclear Decommissioning Asset Retirement Obligation [Member] | ' | ' | ' | ' | ' | |||||
Asset Retirement Obligation Roll Forward Analysis [Roll Forward] | ' | ' | ' | ' | ' | |||||
ARO beginning balance | ' | ' | 4,741 | [7] | ' | ' | ||||
Accretion expense | ' | ' | 194 | ' | ' | |||||
Costs incurred to decommission retired plants | ' | ' | -2 | ' | ' | |||||
ARO ending balance | 4,792 | [7] | ' | 4,792 | [7] | ' | ' | |||
Footnotes To Asset Retirement Obligation [Abstract] | ' | ' | ' | ' | ' | |||||
Current Portion of ARO | 10 | ' | 10 | ' | 10 | |||||
PECO Energy Co [Member] | ' | ' | ' | ' | ' | |||||
Nuclear Decommissioning Trust Fund Investments [Abstract] | ' | ' | ' | ' | ' | |||||
Current annual recovery of decommissioning costs | ' | ' | $24 | ' | ' | |||||
[1] | Excludes a liability recorded within Exelonbs and Generationbs Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT Funds. The NDT Funds will be utilized to satisfy the tax obligations as gains and losses are realized. | |||||||||
[2] | Included in Other current liabilities within Exelonbs and Generationbs Consolidated Balance Sheets. | |||||||||
[3] | Cumulative withdrawals since September 1, 2010. | |||||||||
[4] | 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. | |||||||||
[5] | Net unrealized gains related to Generation's NDT funds associated with Non-Regulatory Agreement Units are included within Other, net in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. | |||||||||
[6] | Excludes $9 million of net unrealized losses and $22 million of net unrealized gains related to the Zion Station pledged assets for the three months ended September 30, 2013 and 2012, respectively, and $5 million of net unrealized losses and $60 million of net unrealized gains related to the Zion Station pledged assets for the nine months ended September 30, 2013 and 2012, respectively. Net unrealized gains (losses) related to Zion Station pledged assets are included in the Payable for Zion Station decommissioning on Exelon's and Generation's Consolidated Balance Sheets. | |||||||||
[7] | Includes $10 million as the current portion of the ARO at September 30, 2013 and December 31, 2012, respectively, which is included in Other current liabilities on Exelon's and Generation's Consolidated Balance Sheets. |
Retirement_Benefits_Details
Retirement Benefits (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||||||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | ||||
Pension And Other Postretirement Benefit Contributions [Abstract] | ' | ' | ' | ' | ||||
Pension and non-pension postretirement benefit contributions | ' | ' | $360 | $131 | ||||
Defined Contribution Plan Contributions By Employer [Abstract] | ' | ' | ' | ' | ||||
Savings plan matching contributions | 18 | 19 | 61 | 55 | ||||
Exelon Legacy Benefit Plans [Member] | ' | ' | ' | ' | ||||
Changes in plan assets and benefit obligations recognized in OCI and regulatory assets: | ' | ' | ' | ' | ||||
Changes in plan assets and benefit obligations recognized in OCI | ' | ' | -75 | ' | ||||
Changes in plan assets and benefit obligations recognized in regulatory assets | ' | ' | 93 | ' | ||||
Constellation Legacy Benefit Plans [Member] | ' | ' | ' | ' | ||||
Changes in plan assets and benefit obligations recognized in OCI and regulatory assets: | ' | ' | ' | ' | ||||
Changes in plan assets and benefit obligations recognized in OCI | ' | ' | 2 | ' | ||||
Changes in plan assets and benefit obligations recognized in regulatory assets | ' | ' | 14 | ' | ||||
Business Services Company [Member] | ' | ' | ' | ' | ||||
Defined Benefit Plan Expense Included In Capital And Operational And Maintenance Expense [Abstract] | ' | ' | ' | ' | ||||
Amount included in capital and operating & maintenance expense | 24 | [1] | 20 | [1] | 58 | [1] | 63 | [1] |
Defined Contribution Plan Contributions By Employer [Abstract] | ' | ' | ' | ' | ||||
Savings plan matching contributions | 1 | 2 | 5 | 6 | ||||
Exelon Generation Co L L C [Member] | ' | ' | ' | ' | ||||
Pension And Other Postretirement Benefit Contributions [Abstract] | ' | ' | ' | ' | ||||
Pension and non-pension postretirement benefit contributions | ' | ' | 123 | 48 | ||||
Defined Benefit Plan Expense Included In Capital And Operational And Maintenance Expense [Abstract] | ' | ' | ' | ' | ||||
Amount included in capital and operating & maintenance expense | 87 | 85 | 259 | 259 | ||||
Defined Contribution Plan Contributions By Employer [Abstract] | ' | ' | ' | ' | ||||
Savings plan matching contributions | 8 | 9 | 29 | 25 | ||||
Commonwealth Edison Co [Member] | ' | ' | ' | ' | ||||
Pension And Other Postretirement Benefit Contributions [Abstract] | ' | ' | ' | ' | ||||
Pension and non-pension postretirement benefit contributions | ' | ' | 120 | 19 | ||||
Defined Benefit Plan Expense Included In Capital And Operational And Maintenance Expense [Abstract] | ' | ' | ' | ' | ||||
Amount included in capital and operating & maintenance expense | 77 | 75 | 231 | 212 | ||||
Defined Contribution Plan Contributions By Employer [Abstract] | ' | ' | ' | ' | ||||
Savings plan matching contributions | 6 | 5 | 16 | 14 | ||||
PECO Energy Co [Member] | ' | ' | ' | ' | ||||
Pension And Other Postretirement Benefit Contributions [Abstract] | ' | ' | ' | ' | ||||
Pension and non-pension postretirement benefit contributions | ' | ' | 10 | 12 | ||||
Defined Benefit Plan Expense Included In Capital And Operational And Maintenance Expense [Abstract] | ' | ' | ' | ' | ||||
Amount included in capital and operating & maintenance expense | 11 | 12 | 32 | 38 | ||||
Defined Contribution Plan Contributions By Employer [Abstract] | ' | ' | ' | ' | ||||
Savings plan matching contributions | 2 | 2 | 6 | 5 | ||||
Baltimore Gas and Electric Company [Member] | ' | ' | ' | ' | ||||
Pension And Other Postretirement Benefit Contributions [Abstract] | ' | ' | ' | ' | ||||
Pension and non-pension postretirement benefit contributions | ' | ' | 16 | 13 | ||||
Defined Benefit Plan Expense Included In Capital And Operational And Maintenance Expense [Abstract] | ' | ' | ' | ' | ||||
Amount included in capital and operating & maintenance expense | 14 | 14 | 41 | [2] | 46 | [2] | ||
Defined Contribution Plan Contributions By Employer [Abstract] | ' | ' | ' | ' | ||||
Savings plan matching contributions | 1 | [3] | 1 | [3] | 5 | [3] | 5 | [3] |
Pension Plans Defined Benefit [Member] | ' | ' | ' | ' | ||||
Change in benefit obligation: | ' | ' | ' | ' | ||||
Service cost | 79 | 76 | 238 | 211 | ||||
Interest cost | 163 | 181 | 488 | 524 | ||||
Settlements | ' | -9 | ' | -9 | ||||
Change in plan assets: | ' | ' | ' | ' | ||||
Settlements | ' | -9 | ' | -9 | ||||
Components of net periodic benefit cost: | ' | ' | ' | ' | ||||
Service cost | 79 | 76 | 238 | 211 | ||||
Interest cost | 163 | 181 | 488 | 524 | ||||
Expected return on assets | -253 | -258 | -761 | -742 | ||||
Amortization of: | ' | ' | ' | ' | ||||
Prior service cost (credit) | 3 | 5 | 10 | 12 | ||||
Actuarial (loss) gain | 140 | 117 | 421 | 338 | ||||
Settlement charges | 9 | ' | 9 | ' | ||||
Contractual termination benefit cost | ' | ' | ' | 14 | [4] | |||
Net periodic benefit cost | 141 | 130 | 405 | 366 | ||||
Pension Plans Defined Benefit [Member] | Exelon Legacy Benefit Plans [Member] | ' | ' | ' | ' | ||||
Change in plan assets: | ' | ' | ' | ' | ||||
Fair value of net plan assets at end of year | 8 | ' | 8 | ' | ||||
Pension Plans Defined Benefit [Member] | Constellation Legacy Benefit Plans [Member] | ' | ' | ' | ' | ||||
Valuation Adjustment Impact [Abstract] | ' | ' | ' | ' | ||||
Benefit obligation increase (decrease) reflecting actual census data | ' | ' | 23 | ' | ||||
Other Postretirement Benefit Plans Defined Benefit [Member] | ' | ' | ' | ' | ||||
Change in benefit obligation: | ' | ' | ' | ' | ||||
Service cost | 41 | 38 | 122 | 114 | ||||
Interest cost | 48 | 53 | 145 | 157 | ||||
Components of net periodic benefit cost: | ' | ' | ' | ' | ||||
Service cost | 41 | 38 | 122 | 114 | ||||
Interest cost | 48 | 53 | 145 | 157 | ||||
Expected return on assets | -33 | -28 | -99 | -86 | ||||
Amortization of: | ' | ' | ' | ' | ||||
Transition obligation | ' | 2 | ' | 8 | ||||
Prior service cost (credit) | -4 | -3 | -14 | -10 | ||||
Actuarial (loss) gain | 20 | 19 | 62 | 58 | ||||
Curtailments charges | ' | -5 | ' | -7 | ||||
Contractual termination benefit cost | ' | ' | ' | 6 | [4] | |||
Net periodic benefit cost | 72 | 76 | 216 | 240 | ||||
Other Postretirement Benefit Plans Defined Benefit [Member] | Exelon Legacy Benefit Plans [Member] | ' | ' | ' | ' | ||||
Change in plan assets: | ' | ' | ' | ' | ||||
Fair value of net plan assets at end of year | -39 | ' | -39 | ' | ||||
Other Postretirement Benefit Plans Defined Benefit [Member] | Constellation Legacy Benefit Plans [Member] | ' | ' | ' | ' | ||||
Valuation Adjustment Impact [Abstract] | ' | ' | ' | ' | ||||
Benefit obligation increase (decrease) reflecting actual census data | ' | ' | ($12) | ' | ||||
[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 September 30, 2012, ComEd and BGE each recorded a regulatory asset of $1 million related to their BSC-billed portion of the second quarter 2012 contractual termination benefit charge. | |||||||
[2] | BGE's pension and postretirement benefit costs for the nine months ended September 30, 2012 include $12 million of costs incurred prior to the closing of Exelon's merger with Constellation on March 12, 2012. These amounts are not included in Exelon's net periodic benefit costs for the nine months ended September 30, 2012 shown in the first table of the Defined Benefit Pension and Other Postretirement Benefits section above. | |||||||
[3] | BGE's matching contributions for the nine months ended September 30, 2012 include $1 million of costs incurred prior to the closing of Exelon's merger with Constellation on March 12, 2012, which is not included in Exelon's matching contributions for the nine months ended September 30, 2012. | |||||||
[4] | ComEd and BGE established regulatory assets of $1 million and $4 million, respectively, for their portion of the second quarter 2012 contractual termination benefit charge. |
Retirement_Benefits_Assumption
Retirement Benefits - Assumptions Used In Calculations (Details) | 9 Months Ended |
Sep. 30, 2013 | |
Pension Plans Defined Benefit [Member] | ' |
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Net Periodic Benefit Cost [Abstract] | ' |
Expected return on plan assets | 7.50% |
Discount rate | 3.92% |
Other Postretirement Benefit Plans Defined Benefit [Member] | ' |
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Net Periodic Benefit Cost [Abstract] | ' |
Expected return on plan assets | 6.45% |
Discount rate | 4.00% |
Retirement_Benefits_Fair_Value
Retirement Benefits - Fair Value Recurring Basis (Details) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 | ||
In Millions, unless otherwise specified | ||||
Fair Value Defined Benefit Plan Measured On Recurring Basis Financial Statement Captions [Line Items] | ' | ' | ||
Cash equivalents | $1 | [1] | $995 | [1] |
[1] | Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value. |
Retirement_Benefits_Additional
Retirement Benefits - Additional (Details) (USD $) | Sep. 30, 2013 |
In Millions, unless otherwise specified | |
Defined Benefit Plan Contributions [Abstract] | ' |
Expected qualified pension plan contributions | $255 |
Expected non-qualified pension plan contributions | 82 |
Expected other postretirement benefit plan contributions | 276 |
Exelon Generation Co L L C [Member] | ' |
Defined Benefit Plan Contributions [Abstract] | ' |
Expected qualified pension plan contributions | 113 |
Expected non-qualified pension plan contributions | 7 |
Expected other postretirement benefit plan contributions | 108 |
Commonwealth Edison Co [Member] | ' |
Defined Benefit Plan Contributions [Abstract] | ' |
Expected qualified pension plan contributions | 115 |
Expected non-qualified pension plan contributions | 1 |
Expected other postretirement benefit plan contributions | 112 |
PECO Energy Co [Member] | ' |
Defined Benefit Plan Contributions [Abstract] | ' |
Expected qualified pension plan contributions | 11 |
Expected non-qualified pension plan contributions | 0 |
Expected other postretirement benefit plan contributions | 21 |
Baltimore Gas and Electric Company [Member] | ' |
Defined Benefit Plan Contributions [Abstract] | ' |
Expected non-qualified pension plan contributions | 2 |
Expected other postretirement benefit plan contributions | $17 |
Preferred_Securities_Details
Preferred Securities (Details) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
In Millions, unless otherwise specified | ||
Temporary Equity [Line Items] | ' | ' |
Dollar amount | $0 | $87 |
PECO Energy Co [Member] | ' | ' |
Temporary Equity [Line Items] | ' | ' |
Dollar amount | ' | $87 |
StockBased_Compensation_Plans_2
Stock-Based Compensation Plans (Details) (USD $) | 3 Months Ended | 9 Months Ended | 9 Months Ended | 12 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | |||||||||||||||||||||
In Millions, except Share data, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | ||||||||
Performance Share Awards [Member] | Performance Share Awards [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] | 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] | Business Services Company [Member] | Business Services Company [Member] | Business Services Company [Member] | Business Services Company [Member] | ||||||||||||||
Common Stock [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Common Stock without par - Authorized | 2,000,000,000 | ' | 2,000,000,000 | ' | 2,000,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Common Stock without par - Outstanding | 856,563,385 | ' | 856,563,385 | ' | 855,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Authorized Shares for LTIP [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Authorized Shares for LTIP | 16,000,000 | ' | 16,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Share Based Compensation Components [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Performance shares | $12 | $5 | $41 | $32 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Stock options | 1 | 2 | 3 | 13 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Restricted stock units | 13 | 12 | 49 | 41 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Other stock-based awards | 1 | 1 | 4 | 3 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Total stock-based compensation included in operating and maintenance expense | 27 | 20 | 97 | 89 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Income Tax Benefit | -10 | -8 | -37 | -34 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Total after-tax stock based compensation expense | 17 | 12 | 60 | 55 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Share Based Compensation Pre Tax Expense [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Pre-tax stock based compensation expense | 27 | 20 | 97 | 89 | ' | ' | ' | 10 | 9 | 38 | 33 | 3 | 2 | 7 | 9 | 1 | 1 | 4 | 4 | 1 | [1] | 1 | [1] | 5 | [1] | 4 | [1] | 12 | [2] | 7 | [2] | 43 | [2],[3] | 39 | [2],[3] |
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Nonvested Roll Forward | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Expected Payout Minimum | ' | ' | ' | ' | ' | 50.00% | 75.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Expected Payout Maximum | ' | ' | ' | ' | ' | 150.00% | 125.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Additional Information Regarding Stock Options Exercised [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Unrecognized compensation costs related to nonvested stock options | 3 | ' | 3 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Weighted Average Period Non Vested Stock Options Are Expected To Be Recognized Over | '1 year 9 months 22 days | ' | '1 year 9 months 22 days | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Restricted Stock Units [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Obligations related to outstanding restricted stock units not yet settled | 67 | ' | 67 | ' | 58 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Obligations related to outstanding restricted stock units that will be settled in cash | 0 | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Fair value of settled restricted stock | 3 | 4 | 26 | 23 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Unrecognized compensation costs related to nonvested restricted stock units | 69 | ' | 69 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Weighted average period | '2 years 2 months 13 days | ' | '2 years 2 months 13 days | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Performance Share Awards [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Percentage of current performance share awards settled in stock | ' | ' | 50.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Percentage of current performance share awards settled in cash | ' | ' | 50.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Percentage of current performance share awards settled in cash for executive vice presidents and higher officers | ' | ' | 100.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Expected TSR Percentage Increase | ' | ' | 25.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Expected TSR Percentage Decrease | ' | ' | 25.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Expected IPM Percentage Decrease | ' | ' | 50.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Expected IPM Percentage Increase | ' | ' | 20.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Expected IPM Percentage Increase for Senior VPs and above | ' | ' | 10.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Performance shares settled at fair value of | 3 | 3 | 25 | 22 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Performance shares settled at fair value and paid with cash | 3 | 0 | 12 | 3 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Unrecognized compensation costs related to nonvested performance shares | 32 | ' | 32 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Weighted average period | '2 years 3 months 19 days | ' | '2 years 3 months 19 days | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Obligation Related To Outstanding Performance Share Awards [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Total | 63 | ' | 63 | ' | 53 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Performance Share Transition Awards [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Unrecognized compensation costs related to nonvested performance shares transition | $19 | ' | $19 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Weighted average period | '1 year 3 months 20 days | ' | '1 year 3 months 20 days | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
[1] | BGE's stock-based compensation expense (pre-tax) for the nine months ended September 30, 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 nine months ended September 30, 2012 shown in the tables titled Components of Stock-Based Compensation Expense and Subsidiaries 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. | ||||||||||||||||||||||||||||||||||
[3] | 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. |
Earnings_Per_Share_and_Equity_2
Earnings Per Share and Equity (Details) (USD $) | 3 Months Ended | 9 Months Ended | |||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 |
Earnings Per Share And Equity Additional Narrative Information [Abstract] | ' | ' | ' | ' | ' |
Stock options not included in the calculation of diluted common shares outstanding | 20 | 18 | 20 | 13 | ' |
Treasury Stock, Shares held | 35 | ' | 35 | ' | 35 |
Treasury stock, at cost | $2,327 | ' | $2,327 | ' | $2,327 |
Preferred Stock [Line Items] | ' | ' | ' | ' | ' |
Preferred stock redemption premium | ' | ' | 6 | ' | ' |
Earnings Per Share Diluted | ' | ' | ' | ' | ' |
Net income on common stock | 738 | 296 | 1,224 | 782 | ' |
Average common shares outstanding - basic | 857 | 854 | 856 | 804 | ' |
Assumed exercise of stock options, performance share awards and restricted stock | 3 | 3 | 4 | 2 | ' |
Average common shares outstanding - diluted | 860 | 857 | 860 | 806 | ' |
Preferred securities | 0 | ' | 0 | ' | 87 |
Preferred Stock [Member] | Cumulative Preferred Stock [Member] | ' | ' | ' | ' | ' |
Preferred Stock [Line Items] | ' | ' | ' | ' | ' |
PECO Cumulative Preferred Securities Redeemable | 87 | ' | ' | ' | ' |
Retained Earnings | Cumulative Preferred Stock [Member] | ' | ' | ' | ' | ' |
Preferred Stock [Line Items] | ' | ' | ' | ' | ' |
Preferred stock redemption premium | $6 | ' | ' | ' | ' |
Changes_in_Accumulated_Other_C2
Changes in Accumulated Other Comprehensive Income (Changes in accumulated other comprehensive income by component)(Details) (USD $) | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 9 Months Ended | |||||||||||||||||||||||||||||||||||||||||||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | |||||||||||||||||||
Accumulated Net Gain Loss From Designated Or Qualifying Cash Flow Hedges [Member] | Accumulated Net Unrealized Investment Gain Loss [Member] | Accumulated Defined Benefit Plans Adjustment [Member] | Accumulated Translation Adjustment [Member] | Accumulated Equity Investment [Member] | Accumulated Other Comprehensive (Loss) Income, Net | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | ||||||||||||||||||||||||
Accumulated Net Gain Loss From Designated Or Qualifying Cash Flow Hedges [Member] | Accumulated Net Unrealized Investment Gain Loss [Member] | Accumulated Translation Adjustment [Member] | Accumulated Equity Investment [Member] | Accumulated Other Comprehensive (Loss) Income, Net | Accumulated Net Unrealized Investment Gain Loss [Member] | Accumulated Net Unrealized Investment Gain Loss [Member] | Accumulated Net Gain Loss From Designated Or Qualifying Cash Flow Hedges [Member] | Accumulated Net Gain Loss From Designated Or Qualifying Cash Flow Hedges [Member] | ||||||||||||||||||||||||||||||||||||||||
Accumulated Other Comprehensive Income Loss [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance | ' | ' | ($2,767) | [1] | ' | $368 | [1] | ' | ($3,137) | [1] | $0 | [1] | $2 | [1] | ' | ' | ' | $513 | [1] | ' | $512 | [1] | ' | ' | $1 | [1] | ' | ' | $0 | $0 | ' | $1 | [1] | $1 | [1] | $1 | [1] | $1 | [1] | $0 | [1] | $0 | [1] | |||||
OCI before reclassifications | ' | ' | 138 | [1] | ' | 25 | [1] | -1 | [1] | 73 | [1] | -5 | [1] | 46 | [1] | ' | ' | ' | 53 | [1] | ' | 12 | [1] | -1 | [1] | -5 | [1] | 47 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Amounts reclassified from AOCI | ' | ' | -32 | [1],[2],[3] | ' | -194 | [1],[2],[3] | ' | 157 | [1],[2],[3] | ' | 5 | [1],[2],[3] | ' | ' | ' | -323 | [1],[2],[3] | ' | -328 | [1],[2],[3] | ' | ' | 5 | [1],[2],[3] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Net current-period OCI | 12 | -92 | 106 | [1] | 45 | -169 | [1] | ' | 230 | [1] | -5 | [1] | 51 | [1] | ' | -32 | -152 | -270 | [1] | -163 | -316 | [1] | -1 | [1] | -5 | [1] | 52 | [1] | -270 | 1 | ' | ' | 1 | ' | ' | ' | ' | ' | ' | |||||||||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance | -2,661 | [1] | ' | -2,661 | [1] | ' | 199 | [1] | ' | -2,907 | [1] | -5 | [1] | 53 | [1] | ' | 243 | [1] | ' | 243 | [1] | ' | 196 | [1] | -1 | [1] | -5 | [1] | 53 | [1] | ' | ' | 0 | 0 | ' | 1 | [1] | 1 | [1] | 1 | [1] | 1 | [1] | 0 | [1] | 0 | [1] | |
OtherComprehensiveIncomeLossTaxParentheticalDisclosuresAbstract | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||
Prior service costs | ' | 1 | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||
Actuarial loss reclassified to periodic cost, taxes | -33 | -28 | -97 | -82 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||
Transition obligation | ' | 1 | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||
Pension and non-pension postretirement benefit plan valuation adjustment, taxes | 6 | 43 | -44 | 51 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||
Change in unrealized gain (loss) on cash flow hedges, taxes | -35 | -57 | -109 | 36 | ' | ' | ' | ' | ' | ' | -36 | -113 | -209 | -122 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||
Change in unrealized gain (loss) on marketable securities, taxes | ' | ' | ' | 1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||
Change in unrealized gain (loss) on equity investments taxes | 9 | 11 | 32 | 15 | ' | ' | ' | ' | ' | ' | 9 | 11 | 32 | 15 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||
Deferred Compensation Unit Valuation Adjustment tax | ' | ' | 6 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||
Other comprehensive income, income taxes | $1 | ($59) | $70 | $87 | ' | ' | ' | ' | ' | $70 | ($27) | ($102) | ($177) | ($107) | ' | ' | ' | ' | $177 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||
[1] | (a) All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income. | |||||||||||||||||||||||||||||||||||||||||||||||
[2] | (b) See next table for details about these reclassifications. | |||||||||||||||||||||||||||||||||||||||||||||||
[3] | (b) This accumulated other comprehensive income component is included in the computation of net periodic pension and OPEB cost (see note 14 for additional details). |
Changes_in_Accumulated_Other_C3
Changes in Accumulated Other Comprehensive Income (Reclassification out of Accumulated Other Comprehensive Income)(Details) (USD $) | 3 Months Ended | 9 Months Ended | ||||||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | ||||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ||||
Operating revenues | $6,502 | [1] | $6,579 | [1] | $18,725 | [2] | $17,235 | [2] |
Interest Expense | 228 | 240 | 1,091 | 678 | ||||
Other income and deductions | -79 | -145 | -799 | -444 | ||||
Income before income taxes | 1,175 | 458 | 1,968 | 1,232 | ||||
Income taxes | 439 | 161 | 733 | 445 | ||||
Net income (loss) | 736 | 297 | 1,235 | 787 | ||||
Other Comprehensive Income Loss Reclassification Adjustment From AOCI Pension And Other Postretirement Benefit PlansTax [Abstract] | ' | ' | ' | ' | ||||
Prior service costs | ' | 1 | ' | 2 | ||||
Transition obligation | ' | 1 | ' | 2 | ||||
Gain (loss) on equity method investments | 37 | 10 | 7 | -69 | ||||
Reclassification out of Accumulated Other Comprehensive Income [Member] | ' | ' | ' | ' | ||||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ||||
Net income (loss) | -8 | [3] | ' | 32 | [3] | ' | ||
Accumulated Net Gain Loss From Designated Or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | ' | ' | ' | ' | ||||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ||||
Income before income taxes | 83 | [3] | ' | 322 | [3] | ' | ||
Income taxes | -35 | [3] | ' | -128 | [3] | ' | ||
Net income (loss) | 48 | [3] | ' | 194 | [3] | ' | ||
Accumulated Net Gain Loss From Designated Or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Energy Related Derivative [Member] | ' | ' | ' | ' | ||||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ||||
Operating revenues | 84 | [3] | ' | 324 | [3] | ' | ||
Accumulated Net Gain Loss From Designated Or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Cash Flow Hedging [Member] | ' | ' | ' | ' | ||||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ||||
Interest Expense | -1 | [3] | ' | -2 | [3] | ' | ||
Accumulated Defined Benefit Plans Adjustment [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | ' | ' | ' | ' | ||||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ||||
Income before income taxes | -93 | [3] | ' | -259 | [3] | ' | ||
Income taxes | 37 | [3] | ' | 102 | [3] | ' | ||
Net income (loss) | -56 | [3] | ' | -157 | [3] | ' | ||
Other Comprehensive Income Loss Reclassification Adjustment From AOCI Pension And Other Postretirement Benefit PlansTax [Abstract] | ' | ' | ' | ' | ||||
Deferred compensation unit | -1 | [3],[4] | ' | -1 | [3],[4] | ' | ||
Accumulated Defined Benefit Plans Adjustment [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Pension Plans Defined Benefit [Member] | ' | ' | ' | ' | ||||
Other Comprehensive Income Loss Reclassification Adjustment From AOCI Pension And Other Postretirement Benefit PlansTax [Abstract] | ' | ' | ' | ' | ||||
Actuarial gains/losses | -92 | [3] | ' | -257 | [3] | ' | ||
Accumulated Defined Benefit Plans Adjustment [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Other Equity Investment Reclassified Out of Accumulated Other Comprehensive Income [Member] | ' | ' | ' | ' | ||||
Other Comprehensive Income Loss Reclassification Adjustment From AOCI Pension And Other Postretirement Benefit PlansTax [Abstract] | ' | ' | ' | ' | ||||
Prior service costs | ' | ' | -1 | [3] | ' | |||
Equity Method Investments | Reclassification out of Accumulated Other Comprehensive Income [Member] | ' | ' | ' | ' | ||||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ||||
Income before income taxes | 0 | ' | -8 | [3] | ' | |||
Income taxes | 0 | ' | 3 | [3] | ' | |||
Net income (loss) | 0 | ' | -5 | [3] | ' | |||
Other Comprehensive Income Loss Reclassification Adjustment From AOCI Pension And Other Postretirement Benefit PlansTax [Abstract] | ' | ' | ' | ' | ||||
Gain (loss) on equity method investments | 0 | ' | -8 | [3] | ' | |||
Exelon Generation Co L L C [Member] | ' | ' | ' | ' | ||||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ||||
Operating revenues | 4,255 | 4,031 | 11,858 | 10,539 | ||||
Interest Expense | 82 | 85 | 257 | 223 | ||||
Other income and deductions | 52 | -2 | -28 | -38 | ||||
Income before income taxes | 773 | 172 | 1,231 | 792 | ||||
Income taxes | 288 | 85 | 436 | 373 | ||||
Net income (loss) | 485 | 87 | 795 | 419 | ||||
Other Comprehensive Income Loss Reclassification Adjustment From AOCI Pension And Other Postretirement Benefit PlansTax [Abstract] | ' | ' | ' | ' | ||||
Gain (loss) on equity method investments | 37 | 10 | 7 | -69 | ||||
Exelon Generation Co L L C [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | ' | ' | ' | ' | ||||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ||||
Net income (loss) | 50 | [3] | ' | 323 | [3] | ' | ||
Exelon Generation Co L L C [Member] | Accumulated Net Gain Loss From Designated Or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | ' | ' | ' | ' | ||||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ||||
Interest Expense | ' | ' | 0 | [3] | ' | |||
Income before income taxes | 83 | [3] | ' | 543 | [3] | ' | ||
Income taxes | -33 | [3] | ' | -215 | [3] | ' | ||
Net income (loss) | 50 | [3] | ' | 328 | [3] | ' | ||
Other Comprehensive Income Loss Reclassification Adjustment From AOCI Pension And Other Postretirement Benefit PlansTax [Abstract] | ' | ' | ' | ' | ||||
Gain (loss) on equity method investments | ' | ' | -8 | [3] | ' | |||
Exelon Generation Co L L C [Member] | Accumulated Net Gain Loss From Designated Or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Energy Related Derivative [Member] | ' | ' | ' | ' | ||||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ||||
Operating revenues | 84 | [3] | ' | 543 | [3] | ' | ||
Exelon Generation Co L L C [Member] | Accumulated Net Gain Loss From Designated Or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Cash Flow Hedging [Member] | ' | ' | ' | ' | ||||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ||||
Interest Expense | -1 | [3] | ' | ' | ' | |||
Exelon Generation Co L L C [Member] | Equity Method Investments | Reclassification out of Accumulated Other Comprehensive Income [Member] | ' | ' | ' | ' | ||||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ||||
Income before income taxes | 0 | ' | -8 | [3] | ' | |||
Income taxes | 0 | ' | 3 | [3] | ' | |||
Net income (loss) | 0 | ' | -5 | [3] | ' | |||
Other Comprehensive Income Loss Reclassification Adjustment From AOCI Pension And Other Postretirement Benefit PlansTax [Abstract] | ' | ' | ' | ' | ||||
Gain (loss) on equity method investments | 0 | ' | ' | ' | ||||
Commonwealth Edison Co [Member] | ' | ' | ' | ' | ||||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ||||
Operating revenues | 1,156 | 1,484 | 3,395 | 4,154 | ||||
Interest Expense | 71 | 71 | 493 | 221 | ||||
Other income and deductions | -67 | -69 | -485 | -218 | ||||
Income before income taxes | 211 | 149 | 233 | 368 | ||||
Income taxes | 85 | 59 | 93 | 149 | ||||
Net income (loss) | 126 | 90 | 140 | 219 | ||||
PECO Energy Co [Member] | ' | ' | ' | ' | ||||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ||||
Operating revenues | 728 | 806 | 2,295 | 2,396 | ||||
Interest Expense | 26 | 29 | 77 | 85 | ||||
Other income and deductions | -28 | -30 | -82 | -88 | ||||
Income before income taxes | 127 | 148 | 414 | 418 | ||||
Income taxes | 35 | 25 | 122 | 118 | ||||
Net income (loss) | 92 | 123 | 292 | 300 | ||||
Baltimore Gas and Electric Company [Member] | ' | ' | ' | ' | ||||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ||||
Operating revenues | 737 | 720 | 2,271 | 2,032 | ||||
Interest Expense | 29 | 35 | 94 | 110 | ||||
Other income and deductions | -25 | -30 | -81 | -92 | ||||
Income before income taxes | 89 | 0 | 267 | -21 | ||||
Income taxes | 36 | 0 | 107 | -7 | ||||
Net income (loss) | $53 | $0 | $160 | ($14) | ||||
[1] | For the three months ended September 30, 2013 and 2012, utility taxes of $21 million and $28 million, respectively, are included in revenues and expenses for Generation. For the three months ended September 30, 2013 and 2012, utility taxes of $65 million and $67 million, respectively, are included in revenues and expenses for ComEd. For the three months ended September 30, 2013 and 2012, utility taxes of $33 million and $40 million, respectively, are included in revenues and expenses for PECO. For the three months ended September 30, 2013 and 2012, utility taxes of $20 million and $20 million, respectively, are included in revenues and expenses for BGE. | |||||||
[2] | For the nine months ended September 30, 2013 and 2012, utility taxes of $60 million and $60 million, respectively, are included in revenues and expenses for Generation. For the nine months ended September 30, 2013 and 2012, utility taxes of $182 million and $182 million, respectively, are included in revenues and expenses for ComEd. For the nine months ended September 30, 2013 and 2012, utility taxes of $97 million and $108 million, respectively, are included in revenues and expenses for PECO. For the nine months ended September 30, 2013 and period of March 12, 2012 through September 30, 2012, utility taxes of $62 million and $42 million, respectively, are included in revenues and expenses for BGE. | |||||||
[3] | (a) All amounts are net of tax. Amounts in parenthesis represent a decrease in net income. | |||||||
[4] | (c) Amortization of deferred compensation unit is allocated to capital and operating and maintenance expense. |
Commitments_and_Contingencies_2
Commitments and Contingencies (Details) (USD $) | 0 Months Ended | 3 Months Ended | 9 Months Ended | 0 Months Ended | 9 Months Ended | 1 Months Ended | 9 Months Ended | 9 Months Ended | 0 Months Ended | 9 Months Ended | 0 Months Ended | 9 Months Ended | 12 Months Ended | 9 Months Ended | 9 Months Ended | 9 Months Ended | 9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Feb. 28, 2012 | Jun. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Apr. 12, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Jan. 31, 2013 | Oct. 31, 2007 | Sep. 30, 2013 | Dec. 31, 2012 | Jan. 31, 2005 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Jan. 31, 2005 | Feb. 09, 2007 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Jul. 11, 2011 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | ||||||||||||||||||||||
Defendants | T | Other Purchase Obligations [Member] | Cotter Corporation [Member] | Total Accrual For Environmental Loss Contingencies [Member] | Total Accrual For Environmental Loss Contingencies [Member] | Accrual For MGP Investigation And Remediation [Member] | Accrual For MGP Investigation And Remediation [Member] | Financial Standby Letter of Credit [Member] | Sithe Guarantee [Member] | TEG And TEP Guarantee [Member] | Nuclear Insurance Premiums [Member] | Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member] | Revenues [Member] | Operating And Maintenance Expense [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Midwest Generation, LLC [Member] | |||||||||||||||||||||||
Defendants | Reactors | Net Capacity Purchases [Member] | Power Purchases [Member] | Transmission Rights Purchases [Member] | Purchased Energy from Equity Investment [Member] | Public Utilities, Inventory, Fuel [Member] | Solar Facility Construction [Member] | Other Purchase Obligations [Member] | Perryman Construction [Member] | Beebe Construction [Member] | Cotter Corporation [Member] | Rossville ash site [Member] | Total Accrual For Environmental Loss Contingencies [Member] | Total Accrual For Environmental Loss Contingencies [Member] | Financial Standby Letter of Credit [Member] | Sithe Guarantee [Member] | TEG And TEP Guarantee [Member] | Nuclear Insurance Premiums [Member] | Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member] | Operating And Maintenance Expense [Member] | Customers | ElectricGenerationStation | DSP Program Electric Procurement Contracts [Member] | Renewable Energy Including Renewable Energy Credits [Member] | Other Purchase Obligations [Member] | Total Accrual For Environmental Loss Contingencies [Member] | Total Accrual For Environmental Loss Contingencies [Member] | Accrual For MGP Investigation And Remediation [Member] | Accrual For MGP Investigation And Remediation [Member] | Financial Standby Letter of Credit [Member] | Trust Preferred Securities [Member] | Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member] | MGPSites | DSP Program Electric Procurement Contracts [Member] | Alternative Energy Credits [Member] | Curtailment Services [Member] | Public Utilities, Inventory, Fuel [Member] | Other Purchase Obligations [Member] | Total Accrual For Environmental Loss Contingencies [Member] | Total Accrual For Environmental Loss Contingencies [Member] | Accrual For MGP Investigation And Remediation [Member] | Accrual For MGP Investigation And Remediation [Member] | Financial Standby Letter of Credit [Member] | Trust Preferred Securities [Member] | Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member] | Claiments | DSP Program Electric Procurement Contracts [Member] | Curtailment Services [Member] | Public Utilities, Inventory, Fuel [Member] | Other Purchase Obligations [Member] | Sixty-Eighth Street Dump [Member] | Total Accrual For Environmental Loss Contingencies [Member] | Financial Standby Letter of Credit [Member] | Trust Preferred Securities [Member] | Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member] | Revenues [Member] | |||||||||||||||||||||||||||||||||||||||||||
States | Customers | MGPSites | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
OpenClaims | MGPSites | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Business Acquisition, Costs Recognized Post Merger [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
BGE rate credit of $100 per residential customer | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $113,000,000 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $113,000,000 | [1] | ' | |||||||||||||||||||
Customer investment fund to invest in energy efficiency and low-income energy assistance to BGE customers | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 113,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Contribution for renewable energy, energy efficiency or related projects in Baltimore | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Length of years for charitable contributions at $7 million per year | ' | ' | '10 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Business Acquisition Charitable Contributions Per Year | ' | ' | 7,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 70,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 35,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 28,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
State funding for offshore wind development projects | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 32,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Miscellaneous tax benefits | ' | ' | -2,000,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -2,000,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Total | ' | ' | 328,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 35,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 139,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Business Acquisition, Costs Recognized Post Merger Footnotes [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Business Acquisition, Equity Contribution | ' | 66,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Commercial Commitments [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Guarantee Obligations Maximum Exposure | ' | ' | 9,518,000,000 | ' | ' | ' | ' | ' | ' | 1,514,000,000 | [2] | 200,000,000 | 95,000,000 | 3,096,000,000 | [3] | 4,908,000,000 | [4] | ' | ' | ' | ' | 5,830,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,463,000,000 | [2] | ' | ' | 3,096,000,000 | [3] | 1,271,000,000 | [5] | ' | ' | 235,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 26,000,000 | [2] | 200,000,000 | 209,000,000 | [6] | 203,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 22,000,000 | [2] | 178,000,000 | 181,000,000 | [7] | 253,000,000 | ' | ' | ' | ' | ' | ' | 1,000,000 | [2] | 250,000,000 | 252,000,000 | [8] | ' | ' | |||||||||
Commercial Commitments Footnote [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Guarantees in support of equity investment | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 211,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 211,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Estimated net exposure for commercial transaction obligations | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 600,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 200,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Nuclear Insurance [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Nuclear insurance liability limit per incident | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 13,600,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Required nuclear liability insurance per site | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 375,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Total of U.S. licensed nuclear reactors | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 104 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Nuclear financial protection pool value | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 13,200,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Maximum assessment mandated by Price-Anderson Act per nuclear reactor for a nuclear incident | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 127,300,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Maximum annual assessment payment mandated by Price-Anderson Act for a nuclear incident | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 19,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Maximum liability per nuclear incident | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,100,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,800,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Guarantees Related To Indemnifications [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Acquisition of interest in subsidiary | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Sale of interest in subsidiary | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 100.00% | 49.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Accrual For Environmental Loss Contingencies [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Accrued environmental liabilities | ' | ' | ' | ' | ' | 345,000,000 | 351,000,000 | 280,000,000 | 298,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 56,000,000 | 42,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 237,000,000 | 261,000,000 | 232,000,000 | 254,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 51,000,000 | 47,000,000 | 48,000,000 | 44,000,000 | ' | ' | ' | 1,000,000 | ' | ' | ' | ' | ' | 1,000,000 | ' | ' | ' | ' | ' | |||||||||||||||||||||
Environmental Issues - MGP Site Contingency [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Total number of MGP sites | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 42 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 26 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 13 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Approved clean-up | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 16 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 16 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Sites under study/remediation | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 26 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
MGP reserve update | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Environmental Issues - Water [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Low end of range of cooling tower cost | ' | ' | 430,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 430,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Consent decree penalty | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Environmental loss contingencies | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 30,000,000 | 15,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8,000,000 | |||||||||||||||||||||
Increase in accrual due to purchase accounting | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Increase in accrual due to an update of costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Environmental Issues - Air [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
States subject to the Cross State Air Pollution Rule | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 28 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Emissions allowance balance | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 64,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Number Of Stations Violating Clean Air Act | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Coal Rail Car Lease Proof of Claims | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 21,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Probable contingency (liability) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 17,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,000,000 | |||||||||||||||||||||
Payments for operating leases | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Environmental Issues - Solid and Hazardous Waste [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
DOJ potential settlement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 90,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Total cost of remediation to be shared by PRPs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 42,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Loss Contingency Number Of Defendants | 15 | ' | ' | ' | 14 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Loss Contingency Number Of Parties Jointly And Severally Liable In Environmental Protection Agency Action | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 19 | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Loss Contingency Esitmate to close site | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
68th Street and Sauer Dumps [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Minimum estimated clean-up costs for all potentially responsible parties | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50,000,000 | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Maximum estimated clean-up costs for all potentially responsible parties | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,700,000 | ' | ' | ' | ' | 64,000,000 | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Climate Change Regulation [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Minimum GHG emissions by stationary sources to qualify for regulation | ' | ' | 100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Minimum additional GHG emissions by stationary sources after a modification | ' | ' | 75,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Effective Number Of Years For Tailoring Rule | ' | ' | '6 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Asbestos Loss Contingency [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Asbestos liability reserve | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 65,000,000 | 63,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Asbestos liability reserve related to open claims | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 17,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,000,000 | |||||||||||||||||||||
Open asbestos liability claims | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 211 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Asbestos liability reserve related to anticipated claims | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 48,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Asbestos reserve adjustment | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Number of claimants | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 480 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
US Department Of Energy Settlements [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Preacquisition contingency asset DOE settlement gain | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 16,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Continuous Power Interruption [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Minimum number of customers ComEd can be held liable to for power interruption | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 30,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Number of customers affected by a major storm | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Number of customers proposed by the ICC that ComEd should not be granted a waiver under Continuous Power Interruption | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 34,559 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Securities Class Action Suit [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Expected settlement amount to resolve class action suit | ' | ' | 4,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Unrecorded Unconditional Purchase Obligation [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Purchase Obligations, Due within One Year | ' | ' | ' | 33,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 296,000,000 | ' | ' | 86,000,000 | [9] | 17,000,000 | [10] | 7,000,000 | [11] | 186,000,000 | 339,000,000 | 180,000,000 | 133,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 142,000,000 | [12] | 20,000,000 | [13] | 7,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 211,000,000 | [14] | 1,000,000 | 0 | 54,000,000 | 19,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 227,000,000 | [15] | 13,000,000 | 46,000,000 | 2,000,000 | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||
Purchase Obligations, Due within Two Years | ' | ' | ' | 38,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,291,000,000 | ' | ' | 396,000,000 | [9] | 124,000,000 | [10] | 26,000,000 | [11] | 745,000,000 | 1,199,000,000 | ' | 178,000,000 | ' | 52,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 323,000,000 | [12] | 67,000,000 | [13] | 41,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 584,000,000 | [14] | 2,000,000 | ' | 128,000,000 | 25,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 669,000,000 | [15] | 46,000,000 | 123,000,000 | 21,000,000 | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||
Purchase Obligations, Due within Three Years | ' | ' | ' | 32,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 478,000,000 | ' | ' | 368,000,000 | [9] | 97,000,000 | [10] | 13,000,000 | [11] | 0 | 1,233,000,000 | ' | 127,000,000 | 80,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 136,000,000 | [12] | 74,000,000 | [13] | 5,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 91,000,000 | [14] | 2,000,000 | ' | 100,000,000 | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 226,000,000 | [15] | 41,000,000 | 52,000,000 | 2,000,000 | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||
Purchase Obligations, Due within Four Years | ' | ' | ' | 31,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 344,000,000 | ' | ' | 285,000,000 | [9] | 57,000,000 | [10] | 2,000,000 | [11] | ' | 1,021,000,000 | ' | 40,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 137,000,000 | [12] | 76,000,000 | [13] | 5,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 0 | [14] | 2,000,000 | ' | 78,000,000 | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 34,000,000 | 51,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||
Purchase Obligations, Due within Five Years | ' | ' | ' | 31,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 241,000,000 | ' | ' | 223,000,000 | [9] | 16,000,000 | [10] | 2,000,000 | [11] | ' | 1,050,000,000 | ' | 38,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 140,000,000 | [12] | 77,000,000 | [13] | 5,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,000,000 | ' | 36,000,000 | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 13,000,000 | 50,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||
Purchase Obligations, Due after Five Years | ' | ' | ' | 104,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 565,000,000 | ' | ' | 526,000,000 | [9] | 5,000,000 | [10] | 34,000,000 | [11] | ' | 3,059,000,000 | ' | 112,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | [12] | 1,290,000,000 | [13] | 19,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6,000,000 | ' | 81,000,000 | 7,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 281,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||
Purchase Obligations, Total | ' | ' | ' | $269,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $3,215,000,000 | ' | ' | $1,884,000,000 | [9] | $316,000,000 | [10] | $84,000,000 | [11] | $931,000,000 | $7,901,000,000 | ' | $628,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $878,000,000 | [12] | $1,604,000,000 | [13] | $82,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | $886,000,000 | [14] | $15,000,000 | $0 | $477,000,000 | $54,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | $1,122,000,000 | [15] | $147,000,000 | $603,000,000 | $25,000,000 | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||
Unrecorded Unconditional Purchase Obligation, Additional Information [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Percentage of ownership interest in CENG (as a percent) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50.01% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
[1] | ____________________ (a)B B B B B B B B Exelon made a $66 million equity contribution to BGE in the second quarter of 2012 to fund the after-tax amount of the rate credit as directed in the MDPSC order approving the merger transaction. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[2] | Non-debt letters of credit maintained to provide credit support for certain transactions as requested by third parties. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[3] | 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 Generationbs nuclear insurance premiums. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[4] | Primarily reflects parental guarantees issued on behalf of Generation to allow the flexibility needed to conduct business with counterparties without having to post other forms of collateral. Also reflects guarantees issued to ensure performance under specific contracts, preferred securities of financing trusts, property leases, indemnifications, NRC minimum funding assurance requirements and $211 million on behalf of CENG nuclear generating facilities for credit support and miscellaneous guarantees. The estimated net exposure for obligations under commercial transactions covered by these guarantees was $0.6 billion at September 30, 2013, which represents the total amount Exelon could be required to fund based on September 30, 2013 market prices. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[5] | Primarily reflects guarantees issued to ensure performance under energy marketing and other specific contracts and $211 million on behalf of CENG nuclear generating facilities for credit support. The estimated net exposure for obligations under commercial transactions covered by these guarantees was $0.2 billion at September 30, 2013, which represents the total amount Generation could be required to fund based on September 30, 2013 market prices. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[6] | Primarily reflects full and unconditional guarantees of $200 million Trust Preferred Securities of ComEd Financing III, which is a 100% owned finance subsidiary of ComEd. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[7] | Primarily reflects full and unconditional guarantees of $178 million Trust Preferred Securities of PECO Trust III and IV, which are 100% owned finance subsidiaries of PECO. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[8] | Primarily reflects full and unconditional guarantees of $250 million Trust Preferred Securities of BGE Capital Trust II, which is a 100% owned finance subsidiary of BGE. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[9] | 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 September 30, 2013, net of fixed capacity payments expected to be received by Generation under contracts to resell such acquired capacity to third parties under long-term capacity sale contracts. These capacity payments represent the fixed, or pre-determined, payment for output from contracted generation facilities. Output in this context generally includes products such as energy, capacity, and various ancillary services associated with generating facilities. Expected payments include certain capacity charges which are contingent on plant availability. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[10] | Power-related purchases include firm REC purchase agreements. The table excludes renewable energy purchases that are contingent in nature. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[11] | Transmission rights purchases include estimated commitments for additional transmission rights that will be required to fulfill firm sales contracts. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[12] | (a)B B B B B B B B ComEd entered into various contracts for the procurement of electricity that started to expire in 2012, and will continue to expire through 2017. ComEd is permitted to recover its electric supply procurement costs from retail customers with no mark-up. See Note 5 b Regulatory Matters for additional information. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[13] | (b)B B B B B B B B ComEd entered into 20-year contracts for renewable energy and RECs beginning June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. Pursuant to the ICCbs Order on December 19, 2012, ComEdbs commitments under the existing long-term contracts for energy and associated RECs were reduced in the first quarter of 2013. See Note 5 b Regulatory Matters for additional information. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[14] | PECO entered into various contracts for the procurement of electric supply to serve its default service customers that expire between 2013 and 2015. PECO is permitted to recover its electric supply procurement costs from default service customers with no mark-up in accordance with its PAPUC-approved DSP Programs. See Note 5 - Regulatory Matters for additional information. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[15] | BGE has entered into various contracts with curtailment services providers related to transactions in PJM's capacity market. See Note 5 - Regulatory Matters for additional information. |
Supplemental_Financial_Informa2
Supplemental Financial Information -Operations (Detail) (USD $) | 3 Months Ended | 9 Months Ended | ||||||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | ||||
Operating revenues [Abstract] | ' | ' | ' | ' | ||||
Total operating revenues | $6,502 | [1] | $6,579 | [1] | $18,725 | [2] | $17,235 | [2] |
Taxes Excluding Income And Excise Taxes [Abstract] | ' | ' | ' | ' | ||||
Total taxes other than income | 277 | 290 | 825 | 737 | ||||
Equity Method Investment Summarized Financial Information Gross Profit Loss [Abstract] | ' | ' | ' | ' | ||||
Total income (loss) in equity method investments | ' | ' | 7 | -69 | ||||
Decommissioning-Related Activities [Abstract] | ' | ' | ' | ' | ||||
Net realized income on decommissioning trust funds - Regulatory Agreement Units | 138 | [3] | 33 | [3] | 221 | [3] | 143 | [3] |
Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units | 35 | [3] | 10 | [3] | 65 | [3] | 77 | [3] |
Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units | 103 | 202 | 196 | 352 | ||||
Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement | 46 | 71 | 70 | 101 | ||||
Net unrealized income (losses) on pledged assets | -9 | 22 | -5 | 60 | ||||
Regulatory offset to decommissioning trust fund-related activities | -189 | [4] | -208 | [4] | -338 | [4] | -453 | [4] |
Investment income | 1 | 5 | 6 | 15 | ||||
Total decommissioning-related activities | 124 | 130 | 209 | 280 | ||||
Long-term lease income | 7 | 7 | 20 | 22 | ||||
Interest income related to uncertain income tax positions | 0 | 0 | 24 | 14 | ||||
Credit facility termination fees | 0 | -43 | 0 | -85 | ||||
AFUDC - equity | 4 | 4 | 16 | 11 | ||||
Other Income | 19 | ' | 36 | ' | ||||
Other Expense | ' | -2 | ' | -4 | ||||
Other, net | 155 | 101 | 311 | 253 | ||||
Exelon Generation Co L L C [Member] | ' | ' | ' | ' | ||||
Operating revenues [Abstract] | ' | ' | ' | ' | ||||
Total operating revenues | 4,255 | 4,031 | 11,858 | 10,539 | ||||
Taxes Excluding Income And Excise Taxes [Abstract] | ' | ' | ' | ' | ||||
Total taxes other than income | 98 | 109 | 292 | 272 | ||||
Equity Method Investment Summarized Financial Information Gross Profit Loss [Abstract] | ' | ' | ' | ' | ||||
Total income (loss) in equity method investments | ' | ' | 7 | -69 | ||||
Decommissioning-Related Activities [Abstract] | ' | ' | ' | ' | ||||
Net realized income on decommissioning trust funds - Regulatory Agreement Units | 138 | [3] | 33 | [3] | 221 | [3] | 143 | [3] |
Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units | 35 | [3] | 10 | [3] | 65 | [3] | 77 | [3] |
Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units | 103 | 202 | 196 | 352 | ||||
Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement | 46 | 71 | 70 | 101 | ||||
Net unrealized income (losses) on pledged assets | -9 | 22 | -5 | 60 | ||||
Regulatory offset to decommissioning trust fund-related activities | -189 | [4] | -208 | [4] | -338 | [4] | -453 | [4] |
Investment income | 0 | 1 | -1 | 2 | ||||
Total decommissioning-related activities | 124 | 130 | 209 | 280 | ||||
Interest income related to uncertain income tax positions | 0 | 1 | 3 | 1 | ||||
Credit facility termination fees | 0 | -43 | 0 | -85 | ||||
AFUDC - equity | 0 | ' | 0 | ' | ||||
Other Income | 10 | ' | 18 | ' | ||||
Other Expense | ' | -6 | ' | -13 | ||||
Other, net | 134 | 83 | 229 | 185 | ||||
Commonwealth Edison Co [Member] | ' | ' | ' | ' | ||||
Operating revenues [Abstract] | ' | ' | ' | ' | ||||
Total operating revenues | 1,156 | 1,484 | 3,395 | 4,154 | ||||
Taxes Excluding Income And Excise Taxes [Abstract] | ' | ' | ' | ' | ||||
Total taxes other than income | 80 | 81 | 225 | 224 | ||||
Decommissioning-Related Activities [Abstract] | ' | ' | ' | ' | ||||
Investment income | 0 | ' | 0 | 1 | ||||
Interest income related to uncertain income tax positions | 0 | 1 | 0 | 1 | ||||
AFUDC - equity | 2 | 1 | 8 | 2 | ||||
Other Income | 5 | 3 | 10 | 8 | ||||
Other, net | 7 | 5 | 18 | 12 | ||||
PECO Energy Co [Member] | ' | ' | ' | ' | ||||
Operating revenues [Abstract] | ' | ' | ' | ' | ||||
Total operating revenues | 728 | 806 | 2,295 | 2,396 | ||||
Taxes Excluding Income And Excise Taxes [Abstract] | ' | ' | ' | ' | ||||
Total taxes other than income | 41 | 48 | 121 | 122 | ||||
Decommissioning-Related Activities [Abstract] | ' | ' | ' | ' | ||||
Investment income | 0 | 0 | -1 | 2 | ||||
Interest income related to uncertain income tax positions | 0 | ' | 1 | ' | ||||
AFUDC - equity | 1 | 1 | 3 | 3 | ||||
Other Income | 0 | 1 | 1 | 1 | ||||
Other, net | 1 | 2 | 4 | 6 | ||||
Baltimore Gas and Electric Company [Member] | ' | ' | ' | ' | ||||
Operating revenues [Abstract] | ' | ' | ' | ' | ||||
Total operating revenues | 737 | 720 | 2,271 | 2,032 | ||||
Taxes Excluding Income And Excise Taxes [Abstract] | ' | ' | ' | ' | ||||
Total taxes other than income | 53 | 48 | 162 | 143 | ||||
Decommissioning-Related Activities [Abstract] | ' | ' | ' | ' | ||||
Investment income | 2 | [5] | 3 | 7 | [5] | 9 | [5] | |
Interest income related to uncertain income tax positions | 0 | ' | 0 | ' | ||||
AFUDC - equity | 1 | 2 | 5 | 8 | ||||
Other Income | 1 | 0 | 1 | 1 | ||||
Other, net | $4 | $5 | $13 | $18 | ||||
[1] | For the three months ended September 30, 2013 and 2012, utility taxes of $21 million and $28 million, respectively, are included in revenues and expenses for Generation. For the three months ended September 30, 2013 and 2012, utility taxes of $65 million and $67 million, respectively, are included in revenues and expenses for ComEd. For the three months ended September 30, 2013 and 2012, utility taxes of $33 million and $40 million, respectively, are included in revenues and expenses for PECO. For the three months ended September 30, 2013 and 2012, utility taxes of $20 million and $20 million, respectively, are included in revenues and expenses for BGE. | |||||||
[2] | For the nine months ended September 30, 2013 and 2012, utility taxes of $60 million and $60 million, respectively, are included in revenues and expenses for Generation. For the nine months ended September 30, 2013 and 2012, utility taxes of $182 million and $182 million, respectively, are included in revenues and expenses for ComEd. For the nine months ended September 30, 2013 and 2012, utility taxes of $97 million and $108 million, respectively, are included in revenues and expenses for PECO. For the nine months ended September 30, 2013 and period of March 12, 2012 through September 30, 2012, utility taxes of $62 million and $42 million, respectively, are included in revenues and expenses for BGE. | |||||||
[3] | Includes investment income and realized gains and losses on sales of investments of the trust funds. | |||||||
[4] | Includes the elimination of NDT fund-related activity for the Regulatory Agreement Units, including the elimination of net income taxes related to all NDT fund activity for those units. See Note 13 b Asset Retirement Obligations of the Exelon 2012 Form 10-K for additional information regarding the accounting for nuclear decommissioning. | |||||||
[5] | Relates to the cash return on BGEbs rate stabilization deferral. See Note 5 - Regulatory Matters for additional information regarding the rate stabilization deferral. |
Supplemental_Financial_Informa3
Supplemental Financial Information - Cash Flow (Details) (USD $) | 9 Months Ended | |||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | ||
Depreciation, Amortization and Accretion [Abstract] | ' | ' | ||
Property, plant and equipment | $1,420 | $1,263 | ||
Regulatory assets | 153 | 89 | ||
Amortization of intangible assets, net | 33 | 24 | ||
Amortization of energy contract assets and liabilities | 342 | [1] | 731 | [1] |
Nuclear fuel | 689 | [1] | 628 | [1] |
Asset retirement obligation accretion | 207 | [2] | 174 | [2] |
Total depreciation, amortization and accretion | 2,844 | 2,909 | ||
Other Non-Cash Operating Activities [Abstract] | ' | ' | ||
Pension and non-pension postretirement benefits costs | 621 | 606 | ||
Provision for uncollectible accounts | 83 | 120 | ||
Provision for Obsolete Inventory | 7 | ' | ||
Stock-based compensation costs | 99 | 75 | ||
Other Decommissioning Related Activity | -110 | [3] | -108 | [3] |
Energy-related options | 87 | [4] | 119 | [4] |
Amortization of regulatory asset related to debt costs | 9 | 13 | ||
Amortization of rate stabilization deferral | 49 | 39 | ||
Amortization of debt fair value adjustment | -28 | -49 | ||
Discrete impacts from EIMA | -206 | [5] | 43 | [5] |
Merger related commitments | -6 | [6] | 179 | [7] |
Severance Costs | ' | 120 | ||
Gain (loss) on equity method investments | -7 | 69 | ||
Impairment in investment of direct financing leases | 14 | ' | ||
Impairment Of Long Lived Asets Held For Use | 149 | ' | ||
Amortization of debt costs | 13 | ' | ||
Other | -36 | 9 | ||
Total other noncash operating activities | 738 | 1,235 | ||
Changes In Other Assets and Liabilities [Abstract] | ' | ' | ||
Under/over-recovered energy and transmission costs | -47 | 20 | ||
Settlement of interest rate swaps | -26 | ' | ||
Other regulatory assets and liabilities | 50 | 454 | ||
Other current assets and liabilities | -169 | 52 | ||
Other noncurrent assets and liabilities | 205 | -40 | ||
Total changes in other assets and liabilities | -35 | -422 | ||
Cash Flow Noncash Investing And Financing Activities Disclosure [Abstract] | ' | ' | ||
Merger with Constellation, common stock issued | ' | 7,365 | ||
Consolidated VIE dividend to non-controlling interest | 63 | ' | ||
Total noncash investing and financing activities | -63 | ' | ||
DOE Smart Grid Investment Grant [Abstract] | ' | ' | ||
Amount included in capital expenditures | 68 | 75 | ||
Smart Grid Grant Reimbursements | 64 | 85 | ||
Exelon Generation Co L L C [Member] | ' | ' | ||
Depreciation, Amortization and Accretion [Abstract] | ' | ' | ||
Property, plant and equipment | 610 | 540 | ||
Regulatory assets | ' | 0 | ||
Amortization of intangible assets, net | 33 | 24 | ||
Amortization of energy contract assets and liabilities | 398 | [1] | 812 | [1] |
Nuclear fuel | 689 | [1] | 628 | [1] |
Asset retirement obligation accretion | 207 | [2] | 174 | [2] |
Total depreciation, amortization and accretion | 1,937 | 2,178 | ||
Other Non-Cash Operating Activities [Abstract] | ' | ' | ||
Pension and non-pension postretirement benefits costs | 259 | 259 | ||
Provision for uncollectible accounts | 16 | 14 | ||
Provision for Obsolete Inventory | 7 | ' | ||
Stock-based compensation costs | 0 | ' | ||
Other Decommissioning Related Activity | -110 | [3] | -108 | [3] |
Energy-related options | 87 | [4] | 119 | [4] |
Amortization of debt fair value adjustment | -28 | -23 | ||
Merger related commitments | ' | 35 | [7] | |
Severance Costs | ' | 34 | ||
Gain (loss) on equity method investments | -7 | 69 | ||
Impairment Of Long Lived Asets Held For Use | 149 | ' | ||
Amortization of debt costs | 7 | ' | ||
Other | -5 | 23 | ||
Total other noncash operating activities | 375 | 422 | ||
Changes In Other Assets and Liabilities [Abstract] | ' | ' | ||
Other current assets and liabilities | -123 | -85 | ||
Other noncurrent assets and liabilities | -40 | -110 | ||
Total changes in other assets and liabilities | -163 | -195 | ||
Cash Flow Noncash Investing And Financing Activities Disclosure [Abstract] | ' | ' | ||
Merger with Constellation, common stock issued | ' | 5,258 | ||
Consolidated VIE dividend to non-controlling interest | 63 | ' | ||
Total noncash investing and financing activities | -63 | ' | ||
Commonwealth Edison Co [Member] | ' | ' | ||
Depreciation, Amortization and Accretion [Abstract] | ' | ' | ||
Property, plant and equipment | 413 | 396 | ||
Regulatory assets | 88 | 62 | ||
Amortization of intangible assets, net | ' | 0 | ||
Total depreciation, amortization and accretion | 501 | 458 | ||
Other Non-Cash Operating Activities [Abstract] | ' | ' | ||
Pension and non-pension postretirement benefits costs | 231 | 212 | ||
Provision for uncollectible accounts | -6 | 38 | ||
Stock-based compensation costs | 0 | ' | ||
Amortization of regulatory asset related to debt costs | 7 | 10 | ||
Discrete impacts from EIMA | -206 | [5] | 43 | [5] |
Amortization of debt costs | 3 | 0 | ||
Other | -3 | 7 | ||
Total other noncash operating activities | 26 | 310 | ||
Changes In Other Assets and Liabilities [Abstract] | ' | ' | ||
Under/over-recovered energy and transmission costs | -63 | 21 | ||
Other regulatory assets and liabilities | 35 | 65 | ||
Other current assets and liabilities | -3 | -8 | ||
Other noncurrent assets and liabilities | 261 | [8] | -72 | |
Total changes in other assets and liabilities | 160 | -124 | ||
Cash Flow Noncash Investing And Financing Activities Disclosure [Abstract] | ' | ' | ||
Allocation Of Tax Benefit From Parent | 175 | ' | ||
Indemnification of like-kind exchange position | 0 | 0 | ||
PECO Energy Co [Member] | ' | ' | ||
Depreciation, Amortization and Accretion [Abstract] | ' | ' | ||
Property, plant and equipment | 164 | 154 | ||
Regulatory assets | 7 | 7 | ||
Amortization of intangible assets, net | ' | 0 | ||
Total depreciation, amortization and accretion | 171 | 161 | ||
Other Non-Cash Operating Activities [Abstract] | ' | ' | ||
Pension and non-pension postretirement benefits costs | 32 | 38 | ||
Provision for uncollectible accounts | 48 | 46 | ||
Stock-based compensation costs | 0 | ' | ||
Amortization of regulatory asset related to debt costs | 2 | 2 | ||
Severance Costs | ' | 1 | ||
Amortization of debt costs | 2 | ' | ||
Other | 0 | 9 | ||
Total other noncash operating activities | 84 | 96 | ||
Changes In Other Assets and Liabilities [Abstract] | ' | ' | ||
Under/over-recovered energy and transmission costs | -10 | -3 | ||
Other regulatory assets and liabilities | 0 | -7 | ||
Other current assets and liabilities | -31 | -56 | ||
Other noncurrent assets and liabilities | -6 | -5 | ||
Total changes in other assets and liabilities | -47 | -57 | ||
DOE Smart Grid Investment Grant [Abstract] | ' | ' | ||
Amount included in capital expenditures | 22 | 45 | ||
Smart Grid Grant Reimbursements | 30 | 55 | ||
Baltimore Gas and Electric Company [Member] | ' | ' | ||
Depreciation, Amortization and Accretion [Abstract] | ' | ' | ||
Property, plant and equipment | 194 | 184 | ||
Regulatory assets | 58 | 34 | ||
Amortization of intangible assets, net | ' | 0 | ||
Total depreciation, amortization and accretion | 252 | 218 | ||
Other Non-Cash Operating Activities [Abstract] | ' | ' | ||
Pension and non-pension postretirement benefits costs | 41 | 44 | ||
Provision for uncollectible accounts | 25 | 28 | ||
Stock-based compensation costs | 0 | ' | ||
Amortization of regulatory asset related to debt costs | 0 | 1 | ||
Amortization of rate stabilization deferral | 49 | 49 | ||
Merger related commitments | -6 | [6] | 28 | [7] |
Amortization of debt costs | 1 | ' | ||
Other | -5 | -2 | ||
Total other noncash operating activities | 105 | 148 | ||
Changes In Other Assets and Liabilities [Abstract] | ' | ' | ||
Under/over-recovered energy and transmission costs | 26 | 21 | ||
Other regulatory assets and liabilities | 85 | 80 | ||
Other current assets and liabilities | -35 | -25 | ||
Other noncurrent assets and liabilities | -25 | 7 | ||
Total changes in other assets and liabilities | -119 | -77 | ||
Cash Flow Noncash Investing And Financing Activities Disclosure [Abstract] | ' | ' | ||
Indemnification of like-kind exchange position | 0 | -66 | ||
DOE Smart Grid Investment Grant [Abstract] | ' | ' | ||
Amount included in capital expenditures | 46 | 30 | ||
Smart Grid Grant Reimbursements | $34 | $30 | ||
[1] | Included in purchased power and fuel expense on the Registrants' Consolidated Statements of Operations and Comprehensive Income | |||
[2] | Included in operating and maintenance expense on the Registrants' Consolidated Statements of Operations and Comprehensive Income | |||
[3] | Includes the elimination of NDT fund-related 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 13 of the Exelon 2012 Form 10-K for additional information regarding the accounting for nuclear decommissioning. | |||
[4] | Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations. | |||
[5] | Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through a pre-established performance-based formula rate tariff. See Note 5 - Regulatory Matters for more information. | |||
[6] | Relates to integration costs to achieve distribution synergies related to the merger transaction. See Note 5 - Regulatory Matters for more information. | |||
[7] | See Note 4 - Mergers and Acquisitions for more information on merger-related commitments. | |||
[8] | Relates primarily to interest payable related to like-kind exchange tax position. See Note 12 b Income Taxes for discussion of the like-kind exchange tax position. |
Supplemental_Financial_Informa4
Supplemental Financial Information - Balance Sheet (Details) (USD $) | 12 Months Ended | ||||
Dec. 31, 2010 | Sep. 30, 2013 | Dec. 31, 2012 | |||
Supplemental Financial Information Textuals [Abstract] | ' | ' | ' | ||
Payment to IRS | $302,000,000 | ' | ' | ||
Capital Leases, Net Investment in Direct Financing Leases [Abstract] | ' | ' | ' | ||
Estimated residual value of leased assets | ' | 1,600,000,000 | ' | ||
Accrued Liabilities Current [Abstract] | ' | ' | ' | ||
Total accrued expenses | ' | 1,540,000,000 | 1,800,000,000 | ||
Property, Plant And Equipment [Abstract] | ' | ' | ' | ||
Accumulated depreciation | ' | 13,366,000,000 | [1] | 12,184,000,000 | [2] |
Accumulated amortization of nuclear fuel | ' | 2,365,000,000 | 2,078,000,000 | ||
Accounts receivable, net | ' | ' | ' | ||
Allowance for uncollectible accounts | ' | 302,000,000 | 293,000,000 | ||
Accumulated Other Comprehensive Income (Loss) [Abstract] | ' | ' | ' | ||
Accumulated other comprehensive income (loss), net | ' | -2,661,000,000 | [3] | -2,767,000,000 | [3] |
Exelon Generation Co L L C [Member] | ' | ' | ' | ||
Accrued Liabilities Current [Abstract] | ' | ' | ' | ||
Total accrued expenses | ' | 925,000,000 | 1,116,000,000 | ||
Property, Plant And Equipment [Abstract] | ' | ' | ' | ||
Accumulated depreciation | ' | 6,848,000,000 | [1] | 6,014,000,000 | [2] |
Accumulated amortization of nuclear fuel | ' | 2,365,000,000 | 2,078,000,000 | ||
Accounts receivable, net | ' | ' | ' | ||
Allowance for uncollectible accounts | ' | 72,000,000 | 84,000,000 | ||
Accumulated Other Comprehensive Income (Loss) [Abstract] | ' | ' | ' | ||
Accumulated other comprehensive income (loss), net | ' | 243,000,000 | [3] | 513,000,000 | [3] |
Commonwealth Edison Co [Member] | ' | ' | ' | ||
Accrued Liabilities Current [Abstract] | ' | ' | ' | ||
Total accrued expenses | ' | 238,000,000 | 295,000,000 | ||
Property, Plant And Equipment [Abstract] | ' | ' | ' | ||
Accumulated depreciation | ' | 3,107,000,000 | 2,998,000,000 | ||
Accounts receivable, net | ' | ' | ' | ||
Allowance for uncollectible accounts | ' | 73,000,000 | 70,000,000 | ||
Accumulated Other Comprehensive Income (Loss) [Abstract] | ' | ' | ' | ||
Accumulated other comprehensive income (loss), net | ' | 0 | 0 | ||
PECO Energy Co [Member] | ' | ' | ' | ||
Accrued Liabilities Current [Abstract] | ' | ' | ' | ||
Total accrued expenses | ' | 91,000,000 | 82,000,000 | ||
Financing Receivable Recorded Investment [Line Items] | ' | ' | ' | ||
Installment plan receivables | ' | 22,000,000 | 18,000,000 | ||
Installment plan receivables uncollectible accounts reserve | ' | -22,000,000 | -15,000,000 | ||
Property, Plant And Equipment [Abstract] | ' | ' | ' | ||
Accumulated depreciation | ' | 2,914,000,000 | 2,797,000,000 | ||
Accounts receivable, net | ' | ' | ' | ||
Allowance for uncollectible accounts | ' | 119,000,000 | 99,000,000 | ||
Accumulated Other Comprehensive Income (Loss) [Abstract] | ' | ' | ' | ||
Accumulated other comprehensive income (loss), net | ' | 1,000,000 | [3] | 1,000,000 | [3] |
PECO Energy Co [Member] | Low To Medium Risk [Member] | ' | ' | ' | ||
Financing Receivable Recorded Investment [Line Items] | ' | ' | ' | ||
Installment plan receivables uncollectible accounts reserve | ' | -1,000,000 | -1,000,000 | ||
PECO Energy Co [Member] | Medium Risk [Member] | ' | ' | ' | ||
Financing Receivable Recorded Investment [Line Items] | ' | ' | ' | ||
Installment plan receivables uncollectible accounts reserve | ' | -4,000,000 | -3,000,000 | ||
PECO Energy Co [Member] | High Risk [Member] | ' | ' | ' | ||
Financing Receivable Recorded Investment [Line Items] | ' | ' | ' | ||
Installment plan receivables uncollectible accounts reserve | ' | -17,000,000 | -11,000,000 | ||
Baltimore Gas and Electric Company [Member] | ' | ' | ' | ||
Accrued Liabilities Current [Abstract] | ' | ' | ' | ||
Total accrued expenses | ' | 127,000,000 | 106,000,000 | ||
Property, Plant And Equipment [Abstract] | ' | ' | ' | ||
Accumulated depreciation | ' | 2,658,000,000 | 2,595,000,000 | ||
Accounts receivable, net | ' | ' | ' | ||
Allowance for uncollectible accounts | ' | $38,000,000 | $40,000,000 | ||
[1] | Includes accumulated amortization of nuclear fuel in the reactor core of $2,365 million. | ||||
[2] | Includes accumulated amortization of nuclear fuel in the reactor core of $2,078 million. | ||||
[3] | (a) All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income. |
Segment_Information_Details
Segment Information (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||||||||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | |||||
ReportableSegments | ||||||||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | $6,502 | [1] | $6,579 | [1] | $18,725 | [2] | $17,235 | [2] | ' | |
Income taxes | 439 | 161 | 733 | 445 | ' | |||||
Net income (loss) | 736 | 297 | 1,235 | 787 | ' | |||||
Total assets | 79,661 | ' | 79,661 | ' | 78,561 | |||||
Segment Reporting Additional Information [Abstract] | ' | ' | ' | ' | ' | |||||
Number of reportable segments | ' | ' | 9 | ' | ' | |||||
Unrealized Gain (Loss) on Derivatives | ' | ' | 229 | 377 | ' | |||||
Intersegment Eliminations [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | -668 | [1] | -798 | [1] | -2,003 | [2] | -2,291 | [2] | ' | |
Total assets | -11,488 | ' | -11,488 | ' | -12,316 | |||||
Operating Segments [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | ' | ' | 1,042 | [3] | ' | ' | ||||
Exelon Generation Co L L C [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Additional Information [Abstract] | ' | ' | ' | ' | ' | |||||
Number of reportable segments | ' | ' | 6 | ' | ' | |||||
Exelon Generation Co L L C [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | 373 | [4],[5] | 459 | [4],[5] | 1,083 | [6],[7] | 1,233 | [6],[7] | ' | |
Exelon Generation Co L L C [Member] | Operating Segments [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | 4,255 | [1],[5] | 4,031 | [1],[5] | 11,858 | [2],[7] | 10,539 | [2],[7] | ' | |
Net income (loss) | 485 | [5] | 87 | [5] | 795 | [7] | 419 | [7] | ' | |
Total assets | 40,498 | [5] | ' | 40,498 | [5] | ' | 40,681 | [5] | ||
Segment Reporting Additional Information [Abstract] | ' | ' | ' | ' | ' | |||||
Utility taxes | 21 | 28 | 60 | 60 | ' | |||||
Exelon Generation Co L L C [Member] | Operating Segments [Member] | Baltimore Gas And Electric Company Affiliate [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | 144 | ' | 356 | 223 | ' | |||||
Exelon Generation Co L L C [Member] | Operating Segments [Member] | Commonwealth Edison Co Affiliate [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | 143 | 180 | 409 | 631 | ' | |||||
Segment Reporting Additional Information [Abstract] | ' | ' | ' | ' | ' | |||||
Unrealized Gain (Loss) on Derivatives | 0 | -15 | -7 | -30 | ' | |||||
Exelon Generation Co L L C [Member] | Operating Segments [Member] | PECO Energy Co Affiliate [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | 82 | 171 | 321 | 407 | ' | |||||
Generation Mid Atlantic [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | 1,391 | 1,417 | 3,943 | 3,789 | ' | |||||
Revenue net of purchased power and fuel expense, Total | 864 | 908 | 2,475 | 2,561 | ' | |||||
Generation Mid Atlantic [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | 10 | -11 | 11 | -43 | ' | |||||
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity | 7 | -11 | -2 | -44 | ' | |||||
Generation Mid Atlantic [Member] | Operating Segments [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | 1,381 | [8] | 1,428 | [8] | 3,932 | [3] | 3,832 | [3] | ' | |
Revenue net of purchased power and fuel expense from external customers | 857 | [9] | 919 | [9] | 2,477 | [9] | 2,605 | [9] | ' | |
Generation Mid Atlantic [Member] | Operating Segments [Member] | Baltimore Gas And Electric Company Affiliate [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | ' | 120 | ' | ' | ' | |||||
Generation Midwest [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | 1,013 | 1,200 | 3,271 | 3,619 | ' | |||||
Revenue net of purchased power and fuel expense, Total | 601 | 730 | 2,001 | 2,310 | ' | |||||
Generation Midwest [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | -5 | 7 | -3 | 19 | ' | |||||
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity | -5 | 7 | -1 | 19 | ' | |||||
Generation Midwest [Member] | Operating Segments [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | 1,018 | [8] | 1,193 | [8] | 3,274 | [3] | 3,600 | [3] | ' | |
Revenue net of purchased power and fuel expense from external customers | 606 | [9] | 723 | [9] | 2,002 | [9] | 2,291 | [9] | ' | |
Generation New England [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | 340 | 391 | 933 | 812 | ' | |||||
Revenue net of purchased power and fuel expense, Total | 62 | 81 | 142 | 180 | ' | |||||
Generation New England [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | -1 | 1 | -9 | 36 | ' | |||||
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity | 10 | 1 | -14 | 36 | ' | |||||
Generation New England [Member] | Operating Segments [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | 341 | [8] | 390 | [8] | 942 | [3] | 776 | [3] | ' | |
Revenue net of purchased power and fuel expense from external customers | 52 | [9] | 80 | [9] | 156 | [9] | 144 | [9] | ' | |
Generation New York [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | 184 | 185 | 527 | 372 | ' | |||||
Revenue net of purchased power and fuel expense, Total | -9 | 13 | -17 | 60 | ' | |||||
Generation New York [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | -14 | 2 | -20 | -22 | ' | |||||
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity | -38 | 2 | -31 | -22 | ' | |||||
Generation New York [Member] | Operating Segments [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | 198 | [8] | 183 | [8] | 547 | [3] | 394 | [3] | ' | |
Revenue net of purchased power and fuel expense from external customers | 29 | [9] | 11 | [9] | 14 | [9] | 82 | [9] | ' | |
Generation ERCOT [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | 427 | 533 | 1,034 | 1,074 | ' | |||||
Revenue net of purchased power and fuel expense, Total | 144 | 158 | 357 | 312 | ' | |||||
Generation ERCOT [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | -3 | 1 | -8 | 1 | ' | |||||
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity | -78 | ' | -120 | 1 | ' | |||||
Generation ERCOT [Member] | Operating Segments [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | 430 | [8] | 532 | [8] | ' | 1,073 | [3] | ' | ||
Revenue net of purchased power and fuel expense from external customers | 222 | [9] | 158 | [9] | 477 | [9] | 311 | [9] | ' | |
Generation Other Regions [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | 271 | [10] | 329 | [10] | 737 | [10] | 651 | [10] | ' | |
Revenue net of purchased power and fuel expense, Total | 41 | [11] | 42 | [11] | 147 | [11] | 90 | [11] | ' | |
Generation Other Regions [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | -7 | [10] | 12 | [10] | 29 | [10] | 40 | [10] | ' | |
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity | -75 | [11] | 12 | [11] | -91 | [11] | 41 | [11] | ' | |
Generation Other Regions [Member] | Operating Segments [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | 278 | [10],[8] | 317 | [10],[8] | 708 | [10],[3] | 611 | [10],[3] | ' | |
Revenue net of purchased power and fuel expense from external customers | 116 | [11],[9] | 30 | [11],[9] | 238 | [11],[9] | 49 | [11],[9] | ' | |
Generation Reportable Segments Total [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | 3,626 | 4,055 | 10,445 | 10,317 | ' | |||||
Revenue net of purchased power and fuel expense, Total | 1,703 | 1,932 | 5,105 | 5,513 | ' | |||||
Generation Reportable Segments Total [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | -20 | 12 | ' | 31 | ' | |||||
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity | -179 | 11 | -259 | 31 | ' | |||||
Generation Reportable Segments Total [Member] | Operating Segments [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | 3,646 | [8] | 4,043 | [8] | 10,445 | [3] | 10,286 | [3] | ' | |
Revenue net of purchased power and fuel expense from external customers | 1,882 | [9] | 1,921 | [9] | 5,364 | [9] | 5,482 | [9] | ' | |
Generation Total Consolidated Group [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | 4,255 | 4,031 | 11,858 | 10,539 | ' | |||||
Revenue net of purchased power and fuel expense from external customers | 2,076 | [9] | 1,909 | [9] | ' | ' | ' | |||
Revenue net of purchased power and fuel expense, Total | 2,076 | 1,909 | 5,564 | 5,521 | ' | |||||
Generation Total Consolidated Group [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | ' | 0 | ' | 0 | ' | |||||
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity | 0 | 0 | ' | ' | ' | |||||
Generation Total Consolidated Group [Member] | Operating Segments [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | 4,255 | [8] | 4,031 | [8] | 11,858 | [3] | 10,539 | [3] | ' | |
Revenue net of purchased power and fuel expense from external customers | ' | ' | 5,564 | [9] | 5,521 | [9] | ' | |||
Generation All Other Segments [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | 629 | [12] | -24 | [12] | 1,413 | [13] | 222 | [13] | ' | |
Revenue net of purchased power and fuel expense, Total | ' | -23 | [14] | 459 | [15] | 8 | [15] | ' | ||
Generation All Other Segments [Member] | Other Segments [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | 609 | [12],[8] | -12 | [12],[8] | 1,413 | [13],[3] | 253 | [13],[3] | ' | |
Revenue net of purchased power and fuel expense from external customers | 194 | [14],[9] | -12 | [14],[9] | 200 | [15],[9] | 39 | [15],[9] | ' | |
Segment Reporting Additional Information [Abstract] | ' | ' | ' | ' | ' | |||||
Amortization of intangible assets related to commodity contracts | 125 | 404 | 603 | 1,089 | ' | |||||
Amortization Of Intangible Assets Related To Commodity Contracts For Revenue Net Purchased Power And Fuel | 44 | 257 | 386 | 793 | ' | |||||
Generation All Other Segments [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | 20 | [12] | -12 | [12] | ' | -31 | [13] | ' | ||
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity | 179 | [14] | -11 | [14] | 259 | [15] | -31 | [15] | ' | |
Commonwealth Edison Co [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | 1 | [4] | 0 | [4] | 2 | [6] | 2 | [6] | ' | |
Commonwealth Edison Co [Member] | Operating Segments [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | 1,156 | [1] | 1,484 | [1] | 3,395 | [2] | 4,154 | [2] | ' | |
Net income (loss) | 126 | 90 | 140 | 219 | ' | |||||
Total assets | 23,686 | ' | 23,686 | ' | 22,905 | |||||
Segment Reporting Additional Information [Abstract] | ' | ' | ' | ' | ' | |||||
Utility taxes | 65 | 67 | 182 | 182 | ' | |||||
PECO Energy Co [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | 1 | [4] | 1 | [4] | 1 | [6] | 3 | [6] | ' | |
PECO Energy Co [Member] | Operating Segments [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | 728 | [1] | 806 | [1] | 2,295 | [2] | 2,396 | [2] | ' | |
Net income (loss) | 92 | 123 | 292 | 300 | ' | |||||
Total assets | 9,745 | ' | 9,745 | ' | 9,353 | |||||
Segment Reporting Additional Information [Abstract] | ' | ' | ' | ' | ' | |||||
Utility taxes | 33 | 40 | 97 | 108 | ' | |||||
Baltimore Gas and Electric Company [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | 2 | [4] | 4 | [4] | 10 | [16],[6] | 7 | [16],[6] | ' | |
Baltimore Gas and Electric Company [Member] | Operating Segments [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | 737 | [1] | 720 | [1] | 2,271 | [16],[2] | 1,388 | [16],[2] | ' | |
Net income (loss) | 53 | ' | 160 | [16] | -50 | [16] | ' | |||
Total assets | 7,657 | ' | 7,657 | ' | 7,506 | |||||
Segment Reporting Additional Information [Abstract] | ' | ' | ' | ' | ' | |||||
Utility taxes | 20 | 20 | 62 | 42 | ' | |||||
Corporate and Other [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenue net of purchased power and fuel expense, Total | 373 | [14] | ' | ' | ' | ' | ||||
Corporate and Other [Member] | Other Segments [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | 294 | [1],[17] | 336 | [1],[17] | 909 | [18],[2] | 1,049 | [18],[2] | ' | |
Net income (loss) | -20 | [17] | -3 | [17] | -152 | [18] | -101 | [18] | ' | |
Total assets | 9,563 | [17] | ' | 9,563 | [17] | ' | 10,432 | [17] | ||
Corporate and Other [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | 294 | [17],[4] | 337 | [17],[4] | 909 | [18],[6] | 1,050 | [18],[6] | ' | |
Segment Elimination [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | |||||
Revenues | $2 | [4] | $3 | [4] | $2 | [6] | $4 | [6] | ' | |
[1] | For the three months ended September 30, 2013 and 2012, utility taxes of $21 million and $28 million, respectively, are included in revenues and expenses for Generation. For the three months ended September 30, 2013 and 2012, utility taxes of $65 million and $67 million, respectively, are included in revenues and expenses for ComEd. For the three months ended September 30, 2013 and 2012, utility taxes of $33 million and $40 million, respectively, are included in revenues and expenses for PECO. For the three months ended September 30, 2013 and 2012, utility taxes of $20 million and $20 million, respectively, are included in revenues and expenses for BGE. | |||||||||
[2] | For the nine months ended September 30, 2013 and 2012, utility taxes of $60 million and $60 million, respectively, are included in revenues and expenses for Generation. For the nine months ended September 30, 2013 and 2012, utility taxes of $182 million and $182 million, respectively, are included in revenues and expenses for ComEd. For the nine months ended September 30, 2013 and 2012, utility taxes of $97 million and $108 million, respectively, are included in revenues and expenses for PECO. For the nine months ended September 30, 2013 and period of March 12, 2012 through September 30, 2012, utility taxes of $62 million and $42 million, respectively, are included in revenues and expenses for BGE. | |||||||||
[3] | Includes all wholesale and retail electric sales from third parties and affiliated sales to ComEd, PECO and BGE. | |||||||||
[4] | Intersegment revenues exclude sales to unconsolidated affiliate entities. The intersegment profit associated with the sale of certain products and services by and between Exelonbs segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in operating revenues in the Consolidated Statements of Operations. | |||||||||
[5] | Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions. Intersegment revenues for Generation for the three months ended September 30, 2013 include revenue from sales to PECO of $ 82 million and sales to BGE of $ 144 million in the Mid-Atlantic region, and sales to ComEd of $ 143 million in the Midwest. For the three months ended September 30, 2012 intersegment revenues for Generation include revenue from sales to PECO of $171 million and sales to BGE of $120 million in the Mid-Atlantic region, and sales to ComEd of $180 million in the Midwest region, net of $15 million related to the unrealized mark-to-market losses related to the ComEd swap, which eliminate upon consolidation. | |||||||||
[6] | Intersegment revenues exclude sales to unconsolidated affiliate entities. The intersegment profit associated with the sale of certain products and services by and between Exelonbs segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in operating revenues in the Consolidated Statements of Operations | |||||||||
[7] | Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions. Intersegment revenues for Generation for the nine months ended September 30, 2013 include revenue from sales to PECO of $ 321 million and sales to BGE of $ 356 million in the Mid-Atlantic region, and sales to ComEd of $ 409 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 nine months ended September 30, 2012 intersegment revenues for Generation include revenue from sales to PECO of $407 million in the Mid-Atlantic region and sales to BGE of $223 million in the Mid-Atlantic region, and sales to ComEd of $631 million in the Midwest region, net of $30 million related to the unrealized mark-to-market losses related to the ComEd swap, which eliminate upon consolidation. | |||||||||
[8] | Includes all electric sales to third parties and affiliated sales to ComEd, PECO and BGE. | |||||||||
[9] | Includes purchases and sales from third parties and affiliated sales to ComEd, PECO and BGE. | |||||||||
[10] | Other regions include the South, West and Canada, which are not considered individually significant. | |||||||||
[11] | Other regions includes the South, West and Canada, which are not considered individually significant. | |||||||||
[12] | 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 $125 million and $404 million, for the three months ended September 30, 2013 and 2012, respectively, and elimination of intersegment revenues. | |||||||||
[13] | 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 at the merger date of $603 million and $1,089 million, for the nine months ended September 30, 2013 and 2012, respectively, and elimination of intersegment revenues. | |||||||||
[14] | 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 $44 million and $257 million for the three months ended September 30, 2013 and 2012, respectively. | |||||||||
[15] | 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 at the merger date of $386 million and $793 million, for the nine months ended September 30, 2013 and 2012, respectively. | |||||||||
[16] | Amounts represent activity recorded at BGE from March 12, 2012, the closing date of the merger, through September 30, 2012. | |||||||||
[17] | Other primarily includes Exelon's corporate operations, shared service entities and other financing and investment activities. | |||||||||
[18] | Other primarily includes Exelonbs corporate operations, shared service entities and other financing and investment activities |
Related_Party_Transactions_Det
Related Party Transactions (Details) (USD $) | 3 Months Ended | 9 Months Ended | 3 Months Ended | 7 Months Ended | 9 Months Ended | 3 Months Ended | 7 Months Ended | 9 Months Ended | 3 Months Ended | 7 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 9 Months Ended | 3 Months Ended | 7 Months Ended | 9 Months Ended | 3 Months Ended | 7 Months Ended | 9 Months Ended | 3 Months Ended | 7 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | |||||||||||||||||||||||||||||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Jun. 30, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Jun. 30, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Jun. 30, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Jun. 30, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Jun. 30, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Jun. 30, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | ||||
Power Purchase Agreement [Member] | Power Purchase Agreement [Member] | Power Purchase Agreement [Member] | Power Purchase Agreement [Member] | Power Service Agency Agreement [Member] | Power Service Agency Agreement [Member] | Power Service Agency Agreement [Member] | Power Service Agency Agreement [Member] | Administrative Services Agreement [Member] | Administrative Services Agreement [Member] | Administrative Services Agreement [Member] | Administrative Services Agreement [Member] | CENG [Member] | CENG [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | ||||||||||
Minimum [Member] | Power Purchase Agreement [Member] | Power Purchase Agreement [Member] | Power Purchase Agreement [Member] | Power Purchase Agreement [Member] | Power Service Agency Agreement [Member] | Power Service Agency Agreement [Member] | Power Service Agency Agreement [Member] | Power Service Agency Agreement [Member] | Administrative Services Agreement [Member] | Administrative Services Agreement [Member] | Administrative Services Agreement [Member] | Administrative Services Agreement [Member] | CENG [Member] | CENG [Member] | ||||||||||||||||||||||||||||||||||||||||||||
Schedule of Equity Method Investments [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Percentage of ownership interest in CENG (as a percent) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50.01% | ' | 50.01% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
CENG | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $93 | $53 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $68 | $58 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Amortization of basis difference in CENG | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -88 | -131 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -31 | -57 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Total equity investment earnings (losses) - CENG | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5 | -78 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 37 | 1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Basis difference in investment in CENG | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 204 | ' | 204 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Operating revenues from affiliates | ' | ' | ' | ' | ' | -269 | -282 | -541 | -748 | 1 | 1 | 2 | 3 | 10 | 14 | 30 | 32 | ' | ' | 384 | 473 | 1,129 | 1,263 | ' | ' | -269 | -282 | -541 | -748 | 1 | 1 | 2 | 3 | 10 | 14 | 30 | 32 | ' | ' | 1 | 0 | 2 | 2 | ' | 1 | 1 | 1 | 3 | ' | 2 | 4 | 10 | 9 | ' | ||||
Purchased power from affiliate | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 143 | 180 | 409 | 631 | ' | 82 | 171 | 321 | 407 | ' | ' | ' | ' | ' | ' | ||||
Operating and maintenance from affiliate | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 140 | 140 | 434 | 467 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 37 | 37 | 113 | 118 | ' | 24 | 27 | 74 | 83 | ' | 21 | 29 | 59 | 97 | ' | ||||
Total interest expense to affiliates, net | 6 | 6 | 19 | 19 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3 | 3 | 10 | 9 | ' | 3 | 3 | 9 | 9 | ' | ' | ' | ' | ' | ' | ||||
Total income (loss) in equity method investments | ' | ' | 7 | -69 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7 | -69 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Cash distribution paid to member | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 550 | 1,384 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Cash dividends paid to parent | ' | ' | 981 | 1,226 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 165 | 95 | ' | ' | ' | 248 | 258 | ' | ' | ' | 0 | 0 | ' | ||||
Contributions from parent | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 66 | ' | ||||
Contributions from member | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Related Party Balance Sheet [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Mark-to-market derivative assets with affiliates | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | 0 | ' | 226 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Total receivables from affiliates (current) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 107 | ' | 107 | ' | 141 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Total receivable from affiliates (noncurrent) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,361 | ' | 2,361 | ' | 2,039 | 410 | ' | 410 | ' | 360 | ' | ' | ' | ' | ' | ||||
Investments in affiliates | 23 | ' | 23 | ' | 22 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | 0 | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6 | ' | 6 | ' | 6 | 8 | ' | 8 | ' | 8 | 8 | ' | 8 | ' | 8 | ||||
Total payables to affiliates (current) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 162 | ' | 162 | ' | 193 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 61 | ' | 61 | ' | 97 | 51 | ' | 51 | ' | 76 | 54 | ' | 54 | ' | 65 | ||||
Mark-to-market derivative liabilities with affiliate (current liabilities) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | 0 | ' | 226 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Total payables to affiliates (noncurrent) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,593 | ' | 2,593 | ' | 2,397 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Equity Method Investment Summarized Financial Information[Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Required purchases of power from CENG's nuclear plants not sold to third parties (as a percent) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 85.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Purchase of nuclear output by EDF (as a percent) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 49.99% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Impact Of Transactions Under Agreements [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Amount receivable from (payable to) related to agreements with CENG | ' | ' | ' | ' | ' | -76 | ' | -86 | -76 | ' | ' | ' | ' | 4 | ' | 5 | 4 | ' | ' | ' | ' | ' | ' | ' | ' | -76 | ' | -86 | -76 | ' | ' | ' | ' | 4 | ' | 5 | 4 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Amortization of energy contract assets and liabilities | ' | ' | $342 | [1] | $731 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $398 | [1] | $812 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
[1] | Included in purchased power and fuel expense on the Registrants' Consolidated Statements of Operations and Comprehensive Income |
Quarterly_Data_Details
Quarterly Data (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||||||
In Millions, except Per Share data, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | ||||
Earnings Per Share Basic [Abstract] | ' | ' | ' | ' | ||||
Average common shares outstanding - basic | 857 | 854 | 856 | 804 | ||||
Earnings Per Share, Basic | $0.86 | $0.35 | $1.43 | $0.97 | ||||
Earnings Per Share Diluted | ' | ' | ' | ' | ||||
Average common shares outstanding - diluted | 860 | 857 | 860 | 806 | ||||
Earnings Per Share, Diluted | $0.86 | $0.35 | $1.42 | $0.97 | ||||
Selected Quarterly Financial Information [Line Items] | ' | ' | ' | ' | ||||
Revenues | $6,502 | [1] | $6,579 | [1] | $18,725 | [2] | $17,235 | [2] |
Operating Income (Loss) | 1,254 | 603 | 2,767 | 1,676 | ||||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 736 | 297 | 1,235 | 787 | ||||
Exelon Generation Co L L C [Member] | ' | ' | ' | ' | ||||
Selected Quarterly Financial Information [Line Items] | ' | ' | ' | ' | ||||
Revenues | 4,255 | 4,031 | 11,858 | 10,539 | ||||
Operating Income (Loss) | 721 | 174 | 1,259 | 830 | ||||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 485 | 87 | 795 | 419 | ||||
Commonwealth Edison Co [Member] | ' | ' | ' | ' | ||||
Selected Quarterly Financial Information [Line Items] | ' | ' | ' | ' | ||||
Revenues | 1,156 | 1,484 | 3,395 | 4,154 | ||||
Operating Income (Loss) | 278 | 218 | 718 | 586 | ||||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 126 | 90 | 140 | 219 | ||||
PECO Energy Co [Member] | ' | ' | ' | ' | ||||
Selected Quarterly Financial Information [Line Items] | ' | ' | ' | ' | ||||
Revenues | 728 | 806 | 2,295 | 2,396 | ||||
Operating Income (Loss) | 155 | 178 | 496 | 506 | ||||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 92 | 123 | 292 | 300 | ||||
Baltimore Gas and Electric Company [Member] | ' | ' | ' | ' | ||||
Selected Quarterly Financial Information [Line Items] | ' | ' | ' | ' | ||||
Revenues | 737 | 720 | 2,271 | 2,032 | ||||
Operating Income (Loss) | 114 | 30 | 348 | 71 | ||||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | $53 | $0 | $160 | ($14) | ||||
[1] | For the three months ended September 30, 2013 and 2012, utility taxes of $21 million and $28 million, respectively, are included in revenues and expenses for Generation. For the three months ended September 30, 2013 and 2012, utility taxes of $65 million and $67 million, respectively, are included in revenues and expenses for ComEd. For the three months ended September 30, 2013 and 2012, utility taxes of $33 million and $40 million, respectively, are included in revenues and expenses for PECO. For the three months ended September 30, 2013 and 2012, utility taxes of $20 million and $20 million, respectively, are included in revenues and expenses for BGE. | |||||||
[2] | For the nine months ended September 30, 2013 and 2012, utility taxes of $60 million and $60 million, respectively, are included in revenues and expenses for Generation. For the nine months ended September 30, 2013 and 2012, utility taxes of $182 million and $182 million, respectively, are included in revenues and expenses for ComEd. For the nine months ended September 30, 2013 and 2012, utility taxes of $97 million and $108 million, respectively, are included in revenues and expenses for PECO. For the nine months ended September 30, 2013 and period of March 12, 2012 through September 30, 2012, utility taxes of $62 million and $42 million, respectively, are included in revenues and expenses for BGE. |