Document_and_Entity_Informatio
Document and Entity Information | 3 Months Ended |
Mar. 31, 2014 | |
Entity Registrant Name | 'EXELON CORP |
Entity Central Index Key | '0001109357 |
Document Type | '10-Q |
Document Period End Date | 31-Mar-14 |
Amendment Flag | 'false |
Document Fiscal Year Focus | '2014 |
Document Fiscal Period Focus | 'Q1 |
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 | 858,721,507 |
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 | 127,016,912 |
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 | |||
In Millions, except Per Share data, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 | ||
Operating revenues [Abstract] | ' | ' | ||
Revenues | $7,237 | [1] | $6,082 | [1] |
Operating expenses | ' | ' | ||
Purchased power and fuel | 4,006 | 2,663 | ||
Purchased power from affiliate | 334 | 318 | ||
Operating and maintenance | 1,858 | 1,764 | ||
Depreciation and amortization | 564 | 543 | ||
Taxes other than income | 293 | 277 | ||
Total operating expenses | 7,055 | 5,565 | ||
Loss on equity method investments | -19 | -9 | ||
Operating income | 163 | 508 | ||
Other income and deductions | ' | ' | ||
Interest expense | -217 | -617 | ||
Interest expense to affiliates, net | -10 | -6 | ||
Other, net | 103 | 172 | ||
Total other income and deductions | -124 | -451 | ||
Income before income taxes | 39 | 57 | ||
Income taxes | -54 | 56 | ||
Net income | 93 | 1 | ||
Net income (loss) attributable to noncontrolling interests and preferred security dividends | -3 | -5 | ||
Net income on common stock | 90 | -4 | ||
Pension and non-pension postretirement benefit plans: | ' | ' | ||
Prior service benefit reclassified to periodic benefit cost, net of tax | -1 | 0 | ||
Actuarial loss reclassified to periodic cost, net of tax | -34 | -51 | ||
Transition obligation reclassified to periodic cost, net of tax | 0 | 0 | ||
Pension and non-pension postretirement benefit plans valuation adjustment | -13 | 75 | ||
Change in unrealized gain (loss) on cash-flow hedges | -25 | -58 | ||
Change in unrealized income (loss) on equity investments | 12 | 28 | ||
Change in unrealized income (loss) on foreign currency translation | -5 | -1 | ||
Change in unrealized gain (loss) on marketable securities | 0 | -1 | ||
Other comprehensive income (loss) | 4 | [2] | 94 | [2] |
Comprehensive income | 97 | 95 | ||
Average shares of common stock outstanding: | ' | ' | ||
Basic | 858 | 855 | ||
Diluted | 861 | 855 | ||
Earnings per average common share - basic | ' | ' | ||
Net income | $0.10 | ($0.01) | ||
Earnings per average common share - diluted | ' | ' | ||
Net income | $0.10 | ($0.01) | ||
Dividends per common share | $0.31 | $0.53 | ||
Exelon Generation Co L L C [Member] | ' | ' | ||
Operating revenues [Abstract] | ' | ' | ||
Operating revenues | 4,056 | 3,141 | ||
Operating revenues from affiliates | 334 | 392 | ||
Revenues | 4,390 | 3,533 | ||
Operating expenses | ' | ' | ||
Purchased power and fuel from affiliate | 349 | 321 | ||
Purchased power | 3,008 | 1,848 | ||
Operating and maintenance | 938 | 965 | ||
Operating and maintenance from affiliate | 149 | 147 | ||
Depreciation and amortization | 211 | 214 | ||
Taxes other than income | 105 | 93 | ||
Total operating expenses | 4,760 | 3,588 | ||
Loss on equity method investments | -19 | -9 | ||
Operating income | -389 | -64 | ||
Other income and deductions | ' | ' | ||
Interest expense | -73 | -65 | ||
Interest expense to affiliates, net | -12 | -17 | ||
Other, net | 90 | 128 | ||
Total other income and deductions | 5 | 46 | ||
Income before income taxes | -384 | -18 | ||
Income taxes | -199 | -1 | ||
Net income | -185 | -17 | ||
Income (Loss) attributable to noncontrolling interest | 0 | -1 | ||
Net income on membership interest | -185 | -18 | ||
Pension and non-pension postretirement benefit plans: | ' | ' | ||
Change in unrealized gain (loss) on cash-flow hedges | -25 | -130 | ||
Change in unrealized income (loss) on equity investments | 12 | 28 | ||
Change in unrealized income (loss) on foreign currency translation | -5 | -1 | ||
Change in unrealized gain (loss) on marketable securities | -3 | -1 | ||
Other comprehensive income (loss) | -21 | [2] | -104 | [2] |
Comprehensive income | -206 | -121 | ||
Commonwealth Edison Co [Member] | ' | ' | ||
Operating revenues [Abstract] | ' | ' | ||
Operating revenues | 1,133 | 1,159 | ||
Operating revenues from affiliates | 1 | 1 | ||
Revenues | 1,134 | 1,160 | ||
Operating expenses | ' | ' | ||
Purchased power | 212 | 237 | ||
Purchased power from affiliate | 108 | 145 | ||
Operating and maintenance | 287 | 292 | ||
Operating and maintenance from affiliate | 39 | 36 | ||
Depreciation and amortization | 173 | 167 | ||
Taxes other than income | 77 | 74 | ||
Total operating expenses | 896 | 951 | ||
Operating income | 238 | 209 | ||
Other income and deductions | ' | ' | ||
Interest expense | -77 | -350 | ||
Interest expense to affiliates, net | -3 | -3 | ||
Other, net | 5 | 5 | ||
Total other income and deductions | -75 | -348 | ||
Income before income taxes | 163 | -139 | ||
Income taxes | 65 | -58 | ||
Net income | 98 | -81 | ||
Pension and non-pension postretirement benefit plans: | ' | ' | ||
Comprehensive income | 98 | -81 | ||
PECO Energy Co [Member] | ' | ' | ||
Operating revenues [Abstract] | ' | ' | ||
Operating revenues | 992 | 895 | ||
Operating revenues from affiliates | 1 | 0 | ||
Revenues | 993 | 895 | ||
Operating expenses | ' | ' | ||
Purchased power and fuel | 377 | 265 | ||
Purchased power from affiliate | 87 | 141 | ||
Operating and maintenance | 256 | 164 | ||
Operating and maintenance from affiliate | 24 | 24 | ||
Depreciation and amortization | 58 | 57 | ||
Taxes other than income | 42 | 41 | ||
Total operating expenses | 844 | 692 | ||
Operating income | 149 | 203 | ||
Other income and deductions | ' | ' | ||
Interest expense | -25 | -26 | ||
Interest expense to affiliates, net | -3 | -3 | ||
Other, net | 2 | 3 | ||
Total other income and deductions | -26 | -26 | ||
Income before income taxes | 123 | 177 | ||
Income taxes | 34 | 55 | ||
Net income | 89 | 122 | ||
Preferred security dividends | 0 | -1 | ||
Net income on common stock | 89 | 121 | ||
Pension and non-pension postretirement benefit plans: | ' | ' | ||
Comprehensive income | 89 | 122 | ||
Baltimore Gas and Electric Company [Member] | ' | ' | ||
Operating revenues [Abstract] | ' | ' | ||
Operating revenues | 1,038 | 876 | ||
Operating revenues from affiliates | 16 | 4 | ||
Revenues | 1,054 | 880 | ||
Operating expenses | ' | ' | ||
Purchased power and fuel | 409 | 313 | ||
Purchased power from affiliate | 120 | 113 | ||
Operating and maintenance | 163 | 124 | ||
Operating and maintenance from affiliate | 25 | 19 | ||
Depreciation and amortization | 108 | 93 | ||
Taxes other than income | 60 | 55 | ||
Total operating expenses | 885 | 717 | ||
Operating income | 169 | 163 | ||
Other income and deductions | ' | ' | ||
Interest expense | -23 | -29 | ||
Interest expense to affiliates, net | -4 | -4 | ||
Other, net | 4 | 5 | ||
Total other income and deductions | -23 | -28 | ||
Income before income taxes | 146 | 135 | ||
Income taxes | 58 | 55 | ||
Net income | 88 | 80 | ||
Preferred security dividends | -3 | -3 | ||
Net income on common stock | 85 | 77 | ||
Pension and non-pension postretirement benefit plans: | ' | ' | ||
Comprehensive income | $88 | $80 | ||
[1] | For the ##D<curmonth> months ended ##D<cyperiod> and ##D<pyfiscal>, utility taxes of $##D<gcytdutiltax> million and $##D<gpytdutiltax> million, respectively, are included in revenues and expenses for Generation. For the ##D<curmonth> months ended ##D<cyperiod> and ##D<pyfiscal>, utility taxes of $##D<ccytdutiltax> million and $##D<cpytdutiltax> million, respectively, are included in revenues and expenses for ComEd. For the ##D<curmonth> months ended ##D<cyperiod> and ##D<pyfiscal>, utility taxes of $##D<pcytdutiltax> million and $##D<ppytdutiltax> million, respectively, are included in revenues and expenses for PECO. For the ##D<curmonth> months ended ##D<cyperiod> and period of March 12, 2012 through ##D<pyperiod>, utility taxes of $##D<bcytdutiltax> million and $##D<bpytdutiltax> million, respectively, are included in revenues and expenses for BGE. | |||
[2] | (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 | |
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Prior service costs | ($1) | $0 |
Actuarial loss reclassified to periodic cost, taxes | 23 | 32 |
Pension and non-pension postretirement benefit plan valuation adjustment, taxes | -7 | 49 |
Change in unrealized gain (loss) on cash flow hedges, taxes | 18 | 33 |
Change in unrealized gain (loss) on equity investments taxes | -7 | -18 |
Actuarial loss reclassified to periodic cost, net of tax | -34 | -51 |
Other Comprehensive Income (Loss), Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service (Cost) Credit, Net of Tax | 1 | 0 |
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Transition (Asset) Obligation, Net of Tax | 0 | 0 |
Exelon Generation Co L L C [Member] | ' | ' |
Change in unrealized gain (loss) on cash flow hedges, taxes | 19 | 86 |
Change in unrealized gain (loss) on marketable securities, taxes | -2 | ' |
Change in unrealized gain (loss) on equity investments taxes | ($7) | ($18) |
Consolidated_Statements_of_Cas
Consolidated Statements of Cash Flows (Unaudited) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Cash flows from operating activities | ' | ' |
Net income | $93 | $1 |
Adjustments to reconcile net income to net cash flows provided by operating activities: | ' | ' |
Depreciation, amortization and accretion | 908 | 1,017 |
Impairment of assets held for sale | 0 | ' |
Deferred income taxes and amortization of investment tax credits | -48 | -610 |
Net fair value changes related to derivatives | 730 | 388 |
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments | -26 | -66 |
Other non-cash operating activities | 272 | 231 |
Changes in assets and liabilities: | ' | ' |
Accounts receivable | -606 | -70 |
Inventories | 80 | 101 |
Accounts payable, accrued expenses and other current liabilities | 157 | -542 |
Option premiums paid, net | 15 | -3 |
Counterparty collateral (posted) received, net | -677 | -186 |
Income taxes | 17 | 632 |
Pension and non-pension postretirement benefit contributions | -472 | -267 |
Other assets and liabilities | -278 | 233 |
Net cash flows provided by operating activities | 165 | 859 |
Cash flows from investing activities | ' | ' |
Capital expenditures | -1,217 | -1,447 |
Proceeds from nuclear decommissioning trust fund sales | 1,825 | 677 |
Investment in nuclear decommissioning trust funds | -1,878 | -729 |
Proceeds from sale of long-lived assets | 18 | ' |
Cash acquired from Constellation | 0 | ' |
Proceeds from sales of investments | 0 | ' |
Purchases of investments | 0 | ' |
Change in restricted cash | -40 | -12 |
Other investing activities | -54 | 40 |
Net cash flows provided by (used in) investing activities | -1,011 | -1,471 |
Cash flows from financing activities | ' | ' |
Payment of accounts receivable agreement | 0 | ' |
Changes in short-term debt | 638 | 233 |
Redemption of preferred securities | 0 | ' |
Issuance of long-term debt | 950 | 149 |
Retirement or repayment of long-term debt | -1,150 | -1 |
Dividends paid on common stock | -266 | -450 |
Dividends paid to former Constellation shareholders | 0 | ' |
Proceeds from employee stock plans | 7 | 12 |
Other financing activities | -28 | -45 |
Net cash flows used in financing activities | 151 | -102 |
Increase (decrease) in cash and cash equivalents | -695 | -714 |
Cash and cash equivalents at beginning of period | 1,609 | 1,486 |
Cash and cash equivalents at end of period | 914 | 772 |
CityPublicServiceBoardSanAntonio [Member] | EquipmentLeasedToOtherPartyMember | ' | ' |
Cash flows from investing activities | ' | ' |
Cash Proceeds from Direct Finance Lease Contract Termination | 335 | 0 |
Exelon Generation Co L L C [Member] | ' | ' |
Cash flows from operating activities | ' | ' |
Net income | -185 | -17 |
Adjustments to reconcile net income to net cash flows provided by operating activities: | ' | ' |
Depreciation, amortization and accretion | 557 | 688 |
Impairment of assets held for sale | 0 | 0 |
Deferred income taxes and amortization of investment tax credits | -161 | -81 |
Net fair value changes related to derivatives | 737 | 406 |
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments | -26 | -66 |
Other non-cash operating activities | 85 | 66 |
Changes in assets and liabilities: | ' | ' |
Accounts receivable | -295 | 65 |
Receivables from and payables to affiliates, net | -3 | -23 |
Inventories | 1 | 29 |
Accounts payable, accrued expenses and other current liabilities | 128 | -261 |
Option premiums paid, net | 15 | -3 |
Counterparty collateral (posted) received, net | -699 | -203 |
Income taxes | -35 | 180 |
Pension and non-pension postretirement benefit contributions | -191 | -115 |
Other assets and liabilities | -103 | -159 |
Net cash flows provided by operating activities | -169 | 506 |
Cash flows from investing activities | ' | ' |
Capital expenditures | -535 | -841 |
Changes in intercompany money pool | -44 | ' |
Proceeds from nuclear decommissioning trust fund sales | 1,825 | 677 |
Investment in nuclear decommissioning trust funds | -1,878 | -729 |
Proceeds from sale of long-lived assets | 18 | ' |
Change in restricted cash | 9 | 3 |
Other investing activities | -77 | 25 |
Net cash flows provided by (used in) investing activities | -594 | -865 |
Cash flows from financing activities | ' | ' |
Changes in short-term debt | 354 | 13 |
Issuance of long-term debt | 300 | 149 |
Retirement or repayment of long-term debt | -532 | -1 |
Distribution to member | -30 | -211 |
Contributions from member | 0 | 0 |
Other financing activities | -21 | -37 |
Net cash flows used in financing activities | 71 | -87 |
Increase (decrease) in cash and cash equivalents | -692 | -446 |
Cash and cash equivalents at beginning of period | 1,258 | 671 |
Cash and cash equivalents at end of period | 566 | 225 |
Exelon Generation Co L L C [Member] | CityPublicServiceBoardSanAntonio [Member] | EquipmentLeasedToOtherPartyMember | ' | ' |
Cash flows from investing activities | ' | ' |
Cash Proceeds from Direct Finance Lease Contract Termination | 335 | ' |
Commonwealth Edison Co [Member] | ' | ' |
Cash flows from operating activities | ' | ' |
Net income | 98 | -81 |
Adjustments to reconcile net income to net cash flows provided by operating activities: | ' | ' |
Depreciation, amortization and accretion | 173 | 167 |
Deferred income taxes and amortization of investment tax credits | 35 | -295 |
Other non-cash operating activities | 36 | 42 |
Changes in assets and liabilities: | ' | ' |
Accounts receivable | -64 | 1 |
Receivables from and payables to affiliates, net | -19 | -32 |
Inventories | 2 | -9 |
Accounts payable, accrued expenses and other current liabilities | -57 | -73 |
Income taxes | 44 | 208 |
Pension and non-pension postretirement benefit contributions | -233 | -118 |
Other assets and liabilities | -24 | 248 |
Net cash flows provided by operating activities | -9 | 58 |
Cash flows from investing activities | ' | ' |
Capital expenditures | -341 | -346 |
Proceeds from sales of investments | 3 | 2 |
Purchases of investments | 0 | -1 |
Change in restricted cash | 0 | 0 |
Other investing activities | 8 | 9 |
Net cash flows provided by (used in) investing activities | -330 | -336 |
Cash flows from financing activities | ' | ' |
Changes in short-term debt | 350 | 220 |
Issuance of long-term debt | 650 | 0 |
Retirement or repayment of long-term debt | -617 | 0 |
Contributions from parent | 38 | 0 |
Dividends paid on common stock | -76 | -55 |
Other financing activities | -1 | -1 |
Net cash flows used in financing activities | 344 | 164 |
Increase (decrease) in cash and cash equivalents | 5 | -114 |
Cash and cash equivalents at beginning of period | 36 | 144 |
Cash and cash equivalents at end of period | 41 | 30 |
PECO Energy Co [Member] | ' | ' |
Cash flows from operating activities | ' | ' |
Net income | 89 | 122 |
Adjustments to reconcile net income to net cash flows provided by operating activities: | ' | ' |
Depreciation, amortization and accretion | 58 | 57 |
Deferred income taxes and amortization of investment tax credits | -2 | 19 |
Other non-cash operating activities | 49 | 39 |
Changes in assets and liabilities: | ' | ' |
Accounts receivable | -110 | -50 |
Receivables from and payables to affiliates, net | 2 | 1 |
Inventories | 45 | 44 |
Accounts payable, accrued expenses and other current liabilities | 117 | -17 |
Income taxes | 33 | 29 |
Pension and non-pension postretirement benefit contributions | -11 | -11 |
Other assets and liabilities | -127 | -38 |
Net cash flows provided by operating activities | 143 | 195 |
Cash flows from investing activities | ' | ' |
Capital expenditures | -184 | -122 |
Changes in intercompany money pool | 0 | -50 |
Change in restricted cash | 0 | 0 |
Other investing activities | 2 | 1 |
Net cash flows provided by (used in) investing activities | -182 | -171 |
Cash flows from financing activities | ' | ' |
Changes in short-term debt | 0 | 0 |
Redemption of preferred securities | 0 | ' |
Issuance of long-term debt | 0 | 0 |
Dividends paid on common stock | -80 | -83 |
Dividends paid on preferred securities | 0 | -1 |
Other financing activities | 0 | 0 |
Net cash flows used in financing activities | -80 | -84 |
Increase (decrease) in cash and cash equivalents | -119 | -60 |
Cash and cash equivalents at beginning of period | 217 | 362 |
Cash and cash equivalents at end of period | 98 | 302 |
Baltimore Gas and Electric Company [Member] | ' | ' |
Cash flows from operating activities | ' | ' |
Net income | 88 | 80 |
Adjustments to reconcile net income to net cash flows provided by operating activities: | ' | ' |
Depreciation, amortization and accretion | 108 | 93 |
Deferred income taxes and amortization of investment tax credits | 27 | 73 |
Other non-cash operating activities | 43 | 42 |
Changes in assets and liabilities: | ' | ' |
Accounts receivable | -132 | -98 |
Receivables from and payables to affiliates, net | -8 | -22 |
Inventories | 33 | 35 |
Accounts payable, accrued expenses and other current liabilities | -16 | -11 |
Counterparty collateral (posted) received, net | 22 | 0 |
Income taxes | 31 | -36 |
Pension and non-pension postretirement benefit contributions | -5 | -5 |
Other assets and liabilities | 44 | 34 |
Net cash flows provided by operating activities | 235 | 185 |
Cash flows from investing activities | ' | ' |
Capital expenditures | -146 | -134 |
Change in restricted cash | -47 | -22 |
Other investing activities | 6 | 2 |
Net cash flows provided by (used in) investing activities | -187 | -154 |
Cash flows from financing activities | ' | ' |
Changes in short-term debt | -66 | 0 |
Issuance of long-term debt | 0 | 0 |
Retirement or repayment of long-term debt | 0 | 0 |
Contributions from parent | 0 | 0 |
Dividends paid on common stock | 0 | 0 |
Dividends paid on preferred securities | -3 | -3 |
Change in restricted cash for dividends | 0 | -3 |
Other financing activities | 13 | 1 |
Net cash flows used in financing activities | -56 | -5 |
Increase (decrease) in cash and cash equivalents | -8 | 26 |
Cash and cash equivalents at beginning of period | 31 | 89 |
Cash and cash equivalents at end of period | $23 | $115 |
Consolidated_Balance_Sheets_Un
Consolidated Balance Sheets (Unaudited) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2013 | |||
In Millions, unless otherwise specified | ||||||
Current assets | ' | ' | ' | |||
CashAndCashEquivalentsNonvariableInterestEntity | $791 | $1,547 | ' | |||
Cash and cash equivalents | 914 | 1,609 | 772 | |||
Cash and cash equivalents of variable interest entities | 123 | 62 | ' | |||
Restricted cash and investments | 111 | 87 | ' | |||
Restricted cash and investments of variable interest entity | 96 | 80 | ' | |||
Accounts receivable, net | ' | ' | ' | |||
Customer | 2,997 | 2,721 | ' | |||
Other | 871 | 1,175 | ' | |||
Accounts receivable of variable interest entities | 458 | 260 | ' | |||
Mark-to-market derivative assets | 756 | 727 | ' | |||
Unamortized energy contracts assets | 326 | 374 | ' | |||
Inventories, net | ' | ' | ' | |||
Fossil fuel | 180 | 276 | ' | |||
Materials and supplies | 843 | 829 | ' | |||
Deferred income taxes | 454 | 573 | ' | |||
Regulatory assets | 768 | 760 | ' | |||
Other | 901 | 666 | ' | |||
Total current assets | 9,675 | 10,137 | ' | |||
Property, plant and equipment, net | 47,742 | 47,330 | ' | |||
Deferred debits and other assets | ' | ' | ' | |||
Regulatory assets | 5,863 | 5,910 | ' | |||
Nuclear decommissioning trust funds | 8,215 | 8,071 | ' | |||
Investments | 825 | 1,165 | ' | |||
Investments in affiliates | 22 | 22 | ' | |||
Investment in CENG | 1,910 | 1,925 | ' | |||
Goodwill | 2,625 | 2,625 | ' | |||
Mark-to-market derivative assets | 571 | 607 | ' | |||
Pledged assets for Zion Station decommissioning | 429 | 458 | ' | |||
Unamortized energy contracts assets | 657 | 710 | ' | |||
Other | 934 | 964 | ' | |||
Deferred income taxes | 0 | ' | 0 | |||
Total deferred debits and other assets | 22,051 | 22,457 | ' | |||
Total assets | 79,468 | 79,924 | 79,924 | |||
Current liabilities | ' | ' | ' | |||
Short-term borrowings | 980 | 341 | ' | |||
Long-term debt due within one year | 292 | 1,424 | ' | |||
Long-term debt of variable interest entities due within one year | 81 | 85 | ' | |||
Accounts payable | 2,475 | 2,314 | ' | |||
Accounts payable of variable interest entities | 286 | 170 | ' | |||
Accrued expenses | 1,364 | 1,633 | ' | |||
Payables to affiliates | 94 | 116 | ' | |||
Deferred income taxes | 22 | 40 | ' | |||
Regulatory liabilities | 336 | 327 | ' | |||
Mark-to-market derivative liabilities | 251 | 159 | ' | |||
Unamortized energy contract liabilities | 238 | 261 | ' | |||
Other | 932 | 858 | ' | |||
Total current liabilities | 7,351 | 7,728 | ' | |||
Long-term debt | 18,247 | 17,325 | ' | |||
Long-term debt of variable financing trusts | 648 | 648 | ' | |||
Long-term debt of variable interest entity | 300 | 298 | ' | |||
Deferred credits and other liabilities | ' | ' | ' | |||
Deferred income taxes and unamortized investment tax credits | 12,810 | 12,905 | ' | |||
Asset retirement obligations | 5,261 | 5,194 | ' | |||
Pension obligations | 1,661 | 1,876 | ' | |||
Non-pension postretirement benefit obligations | 2,042 | 2,190 | ' | |||
Spent nuclear fuel obligation | 1,021 | 1,021 | ' | |||
Regulatory liabilities | 4,458 | 4,388 | ' | |||
Mark-to-market derivative liabilities | 287 | 300 | ' | |||
Unamortized energy contract liabilities | 230 | 266 | ' | |||
Payable for Zion Station decommissioning | 281 | 305 | ' | |||
Other | 2,093 | 2,540 | ' | |||
Total deferred credits and other liabilities | 30,144 | 30,985 | ' | |||
Total liabilities | 56,690 | 56,984 | ' | |||
Shareholders' equity | ' | ' | ' | |||
Common stock | 16,751 | 16,741 | ' | |||
Treasury stock, at cost (35 and 35 shares held at December 31, 2010 and December 31, 2009, respectively) | -2,327 | -2,327 | ' | |||
Retained earnings | 10,180 | 10,358 | ' | |||
Accumulated other comprehensive income (loss), net | -2,036 | [1] | -2,040 | [1] | -2,673 | [1] |
Total shareholders' equity | 22,568 | 22,732 | ' | |||
BGE preference stock not subject to mandatory redemption | 193 | 193 | ' | |||
Noncontrolling interest | 17 | 15 | ' | |||
Total equity | 22,778 | 22,940 | ' | |||
Total liabilities and shareholders' equity | 79,468 | 79,924 | ' | |||
Member's equity | ' | ' | ' | |||
Accumulated other comprehensive income (loss), net | -2,036 | [1] | -2,040 | [1] | -2,673 | [1] |
Removal Costs [Member] | ' | ' | ' | |||
Current liabilities | ' | ' | ' | |||
Regulatory liabilities | 105 | 99 | ' | |||
Deferred credits and other liabilities | ' | ' | ' | |||
Regulatory liabilities | 1,440 | 1,423 | ' | |||
Exelon Generation Co L L C [Member] | ' | ' | ' | |||
Current assets | ' | ' | ' | |||
CashAndCashEquivalentsNonvariableInterestEntity | 443 | 1,196 | ' | |||
Cash and cash equivalents | 566 | 1,258 | 225 | |||
Cash and cash equivalents of variable interest entities | 123 | 62 | ' | |||
Restricted cash and cash equivalents | 19 | 19 | ' | |||
Restricted cash and investments of variable interest entity | 43 | 52 | ' | |||
Accounts receivable, net | ' | ' | ' | |||
Customer | 1,521 | 1,429 | ' | |||
Other | 388 | 353 | ' | |||
Accounts receivable of variable interest entities | 458 | 260 | ' | |||
Mark-to-market derivative assets | 756 | 727 | ' | |||
Mark-to-market derivative assets with affiliates | 0 | 0 | ' | |||
Receivables from affiliates | 122 | 108 | ' | |||
Unamortized energy contracts assets | 326 | 374 | ' | |||
Inventories, net | ' | ' | ' | |||
Fossil fuel | 153 | 164 | ' | |||
Materials and supplies | 679 | 671 | ' | |||
Deferred income taxes | 529 | 475 | ' | |||
Receivable from Exelon intercompany money pool | 0 | 44 | ' | |||
Other | 629 | 505 | ' | |||
Total current assets | 6,189 | 6,439 | ' | |||
Property, plant and equipment, net | 20,132 | 20,111 | ' | |||
Deferred debits and other assets | ' | ' | ' | |||
Nuclear decommissioning trust funds | 8,215 | 8,071 | ' | |||
Investments | 401 | 400 | ' | |||
Investments in affiliates | 0 | 0 | ' | |||
Investment in CENG | 1,910 | 1,925 | ' | |||
Goodwill | 0 | 0 | ' | |||
Mark-to-market derivative assets | 561 | 600 | ' | |||
Mark-to-market derivative assets with affiliates | 0 | 0 | ' | |||
Prepaid pension asset | 1,935 | 1,873 | ' | |||
Pledged assets for Zion Station decommissioning | 429 | 458 | ' | |||
Unamortized energy contracts assets | 657 | 710 | ' | |||
Other | 651 | 645 | ' | |||
Deferred income taxes | 0 | 0 | ' | |||
Total deferred debits and other assets | 14,759 | 14,682 | ' | |||
Total assets | 41,080 | 41,232 | ' | |||
Current liabilities | ' | ' | ' | |||
Short-term borrowings | 377 | 22 | ' | |||
Long-term debt due within one year | 42 | 556 | ' | |||
Long-term debt of variable interest entities due within one year | 5 | 5 | ' | |||
Accounts payable | 1,191 | 1,152 | ' | |||
Accounts payable of variable interest entities | 286 | 170 | ' | |||
Accrued expenses | 831 | 976 | ' | |||
Payables to affiliates | 186 | 181 | ' | |||
Borrowings from Exelon intercompany money pool | 0 | ' | ' | |||
Deferred income taxes | 0 | 25 | ' | |||
Mark-to-market derivative liabilities | 238 | 142 | ' | |||
Unamortized energy contract liabilities | 228 | 249 | ' | |||
Other | 431 | 389 | ' | |||
Total current liabilities | 3,815 | 3,867 | ' | |||
Long-term debt | 5,840 | 5,559 | ' | |||
Long-term debt to affiliate | 1,517 | 1,523 | ' | |||
Long-term debt of variable interest entity | 86 | 86 | ' | |||
Deferred credits and other liabilities | ' | ' | ' | |||
Deferred income taxes and unamortized investment tax credits | 6,223 | 6,295 | ' | |||
Asset retirement obligations | 5,114 | 5,047 | ' | |||
Non-pension postretirement benefit obligations | 796 | 850 | ' | |||
Spent nuclear fuel obligation | 1,021 | 1,021 | ' | |||
Payables to affiliates | 2,773 | 2,740 | ' | |||
Mark-to-market derivative liabilities | 131 | 120 | ' | |||
Unamortized energy contract liabilities | 230 | ' | 266 | |||
Payable for Zion Station decommissioning | 281 | ' | 305 | |||
Other | 745 | 811 | ' | |||
Total deferred credits and other liabilities | 17,314 | 17,455 | ' | |||
Total liabilities | 28,572 | 28,490 | ' | |||
Commitments and contingencies | 0 | 0 | ' | |||
Shareholders' equity | ' | ' | ' | |||
Accumulated other comprehensive income (loss), net | 193 | [1] | 214 | [1] | 409 | [1] |
Noncontrolling interest | 19 | 17 | ' | |||
Member's equity | ' | ' | ' | |||
Membership interest | 8,898 | 8,898 | ' | |||
Undistributed earnings | 3,398 | 3,613 | ' | |||
Accumulated other comprehensive income (loss), net | 193 | [1] | 214 | [1] | 409 | [1] |
Total member's equity | 12,489 | 12,725 | ' | |||
Total equity | 12,508 | 12,742 | ' | |||
Total liabilities and equity | 41,080 | 41,232 | ' | |||
Commonwealth Edison Co [Member] | ' | ' | ' | |||
Current assets | ' | ' | ' | |||
CashAndCashEquivalentsNonvariableInterestEntity | 41 | 36 | ' | |||
Cash and cash equivalents | 41 | 36 | 30 | |||
Restricted cash and cash equivalents | 2 | 2 | ' | |||
Accounts receivable, net | ' | ' | ' | |||
Customer | 475 | 451 | ' | |||
Other | 395 | 584 | ' | |||
Inventories, net | ' | ' | ' | |||
Inventories, net | 107 | 109 | ' | |||
Deferred income taxes | 0 | 0 | ' | |||
Receivable from Exelon intercompany money pool | 172 | ' | ' | |||
Counterparty collateral deposited | 0 | 0 | ' | |||
Regulatory assets | 340 | 329 | ' | |||
Other | 57 | 29 | ' | |||
Total current assets | 1,417 | 1,540 | ' | |||
Property, plant and equipment, net | 14,890 | 14,666 | ' | |||
Deferred debits and other assets | ' | ' | ' | |||
Regulatory assets | 918 | 933 | ' | |||
Investments | 2 | 5 | ' | |||
Investments in affiliates | 6 | 6 | ' | |||
Goodwill | 2,625 | 2,625 | ' | |||
Receivable from affiliate | 2,497 | 2,469 | ' | |||
Prepaid pension asset | 1,663 | 1,583 | ' | |||
Other | 276 | 291 | ' | |||
Total deferred debits and other assets | 7,987 | 7,912 | ' | |||
Total assets | 24,294 | 24,118 | ' | |||
Current liabilities | ' | ' | ' | |||
Short-term borrowings | 534 | 184 | ' | |||
Long-term debt due within one year | 0 | 617 | ' | |||
Accounts payable | 502 | 449 | ' | |||
Accrued expenses | 214 | 307 | ' | |||
Payables to affiliates | 63 | 83 | ' | |||
Deferred income taxes | 116 | 16 | ' | |||
Customer deposits | 133 | 133 | ' | |||
Regulatory liabilities | 158 | 170 | ' | |||
Mark-to-market derivative liabilities | 13 | 17 | ' | |||
Mark-to-market derivative liabilities with affiliate | 0 | 0 | ' | |||
Other | 83 | 72 | ' | |||
Total current liabilities | 1,816 | 2,048 | ' | |||
Long-term debt | 5,707 | 5,058 | ' | |||
Long-term debt of variable financing trusts | 206 | 206 | ' | |||
Deferred credits and other liabilities | ' | ' | ' | |||
Deferred income taxes and unamortized investment tax credits | 4,053 | 4,116 | ' | |||
Asset retirement obligations | 99 | 99 | ' | |||
Non-pension postretirement benefit obligations | 284 | 381 | ' | |||
Regulatory liabilities | 3,566 | 3,512 | ' | |||
Mark-to-market derivative liabilities | 155 | 176 | ' | |||
Other | 818 | 994 | ' | |||
Total deferred credits and other liabilities | 8,975 | 9,278 | ' | |||
Total liabilities | 16,704 | 16,590 | ' | |||
Commitments and contingencies | 0 | 0 | ' | |||
Shareholders' equity | ' | ' | ' | |||
Common stock | 1,588 | 1,588 | ' | |||
Other paid-in capital | 5,230 | 5,190 | ' | |||
Retained earnings | 772 | 750 | ' | |||
Accumulated other comprehensive income (loss), net | 0 | 0 | ' | |||
Total shareholders' equity | 7,590 | 7,528 | ' | |||
Total liabilities and shareholders' equity | 24,294 | 24,118 | ' | |||
Member's equity | ' | ' | ' | |||
Accumulated other comprehensive income (loss), net | 0 | 0 | ' | |||
Commonwealth Edison Co [Member] | Removal Costs [Member] | ' | ' | ' | |||
Current liabilities | ' | ' | ' | |||
Regulatory liabilities | 81 | 78 | ' | |||
Deferred credits and other liabilities | ' | ' | ' | |||
Regulatory liabilities | 1,237 | 1,219 | ' | |||
PECO Energy Co [Member] | ' | ' | ' | |||
Current assets | ' | ' | ' | |||
CashAndCashEquivalentsNonvariableInterestEntity | 98 | 217 | ' | |||
Cash and cash equivalents | 98 | 217 | 302 | |||
Restricted cash and cash equivalents | 2 | 2 | ' | |||
Restricted cash and investments of variable interest entity | 0 | 0 | ' | |||
Accounts receivable, net | ' | ' | ' | |||
Customer | 422 | 360 | ' | |||
Other | 120 | 107 | ' | |||
Inventories, net | ' | ' | ' | |||
Fossil fuel | 12 | 60 | ' | |||
Materials and supplies | 24 | 21 | ' | |||
Deferred income taxes | 83 | 83 | ' | |||
Receivable from Exelon intercompany money pool | 0 | 0 | ' | |||
Prepaid utility taxes | 104 | 3 | ' | |||
Regulatory assets | 28 | 17 | ' | |||
Other | 41 | 36 | ' | |||
Total current assets | 934 | 906 | ' | |||
Property, plant and equipment, net | 6,480 | 6,384 | ' | |||
Deferred debits and other assets | ' | ' | ' | |||
Regulatory assets | 1,465 | 1,448 | ' | |||
Investments | 23 | 23 | ' | |||
Investments in affiliates | 8 | 8 | ' | |||
Receivable from affiliate | 455 | 447 | ' | |||
Prepaid pension asset | 366 | 363 | ' | |||
Other | 35 | 38 | ' | |||
Total deferred debits and other assets | 2,352 | 2,327 | ' | |||
Total assets | 9,766 | 9,617 | ' | |||
Current liabilities | ' | ' | ' | |||
Short-term notes payable - accounts receivable agreement | ' | 0 | ' | |||
Long-term debt due within one year | 250 | 250 | ' | |||
Accounts payable | 389 | 285 | ' | |||
Accrued expenses | 137 | 106 | ' | |||
Payables to affiliates | 60 | 58 | ' | |||
Customer deposits | 49 | 49 | ' | |||
Regulatory liabilities | 84 | 106 | ' | |||
Other | 29 | 37 | ' | |||
Total current liabilities | 998 | 891 | ' | |||
Long-term debt | 1,947 | 1,947 | ' | |||
Long-term debt of variable financing trusts | 184 | 184 | ' | |||
Deferred credits and other liabilities | ' | ' | ' | |||
Deferred income taxes and unamortized investment tax credits | 2,508 | 2,487 | ' | |||
Asset retirement obligations | 29 | 29 | ' | |||
Non-pension postretirement benefit obligations | 290 | 286 | ' | |||
Regulatory liabilities | 641 | 629 | ' | |||
Other | 95 | 99 | ' | |||
Total deferred credits and other liabilities | 3,563 | 3,530 | ' | |||
Total liabilities | 6,692 | 6,552 | ' | |||
Preferred securities | ' | 0 | ' | |||
Shareholders' equity | ' | ' | ' | |||
Common stock | 2,415 | 2,415 | ' | |||
Retained earnings | 658 | 649 | ' | |||
Accumulated other comprehensive income (loss), net | 1 | [1] | 1 | [1] | 1 | [1] |
Total shareholders' equity | 3,074 | 3,065 | ' | |||
Total liabilities and shareholders' equity | 9,766 | 9,617 | ' | |||
Member's equity | ' | ' | ' | |||
Accumulated other comprehensive income (loss), net | 1 | [1] | 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 | ' | ' | ' | |||
CashAndCashEquivalentsNonvariableInterestEntity | 23 | 31 | ' | |||
Cash and cash equivalents | 23 | 31 | 115 | |||
Restricted cash and cash equivalents | 0 | ' | ' | |||
Restricted cash and investments of variable interest entity | 75 | 28 | ' | |||
Accounts receivable, net | ' | ' | ' | |||
Customer | 580 | 480 | ' | |||
Other | 136 | 114 | ' | |||
Income taxes receivable | 0 | 30 | ' | |||
Inventories, net | ' | ' | ' | |||
Fossil fuel | 16 | 53 | ' | |||
Materials and supplies | 32 | 28 | ' | |||
Deferred income taxes | 1 | 2 | ' | |||
Prepaid utility taxes | 28 | 57 | ' | |||
Regulatory assets | 168 | 181 | ' | |||
Other | 8 | 7 | ' | |||
Total current assets | 1,067 | 1,011 | ' | |||
Property, plant and equipment, net | 5,939 | 5,864 | ' | |||
Deferred debits and other assets | ' | ' | ' | |||
Regulatory assets | 504 | 524 | ' | |||
Investments | 4 | 5 | ' | |||
Investments in affiliates | 8 | 8 | ' | |||
Prepaid pension asset | 410 | 423 | ' | |||
Other | 26 | 26 | ' | |||
Total deferred debits and other assets | 952 | 986 | ' | |||
Total assets | 7,958 | 7,861 | ' | |||
Current liabilities | ' | ' | ' | |||
Short-term borrowings | 69 | 135 | ' | |||
Long-term debt due within one year | 0 | 0 | ' | |||
Long-term debt of variable interest entities due within one year | 70 | 70 | ' | |||
Accounts payable | 254 | 270 | ' | |||
Accrued expenses | 111 | 111 | ' | |||
Payables to affiliates | 59 | 55 | ' | |||
Deferred income taxes | 27 | 27 | ' | |||
Customer deposits | 82 | 76 | ' | |||
Regulatory liabilities | 92 | 48 | ' | |||
Other | 54 | 35 | ' | |||
Total current liabilities | 818 | 827 | ' | |||
Long-term debt | 1,746 | 1,746 | ' | |||
Long-term debt of variable financing trusts | 258 | 258 | ' | |||
Long-term debt of variable interest entity | 195 | 195 | ' | |||
Deferred credits and other liabilities | ' | ' | ' | |||
Deferred income taxes and unamortized investment tax credits | 1,801 | 1,773 | ' | |||
Asset retirement obligations | 17 | 19 | ' | |||
Non-pension postretirement benefit obligations | 215 | 217 | ' | |||
Regulatory liabilities | 203 | 204 | ' | |||
Other | 65 | 67 | ' | |||
Total deferred credits and other liabilities | 2,301 | 2,280 | ' | |||
Total liabilities | 5,318 | 5,306 | ' | |||
Commitments and contingencies | 0 | 0 | ' | |||
Shareholders' equity | ' | ' | ' | |||
Common stock | 1,360 | 1,360 | ' | |||
Retained earnings | 1,090 | 1,005 | ' | |||
Total shareholders' equity | 2,450 | 2,365 | ' | |||
BGE preference stock not subject to mandatory redemption | 190 | 190 | ' | |||
Total equity | 2,640 | 2,555 | ' | |||
Total liabilities and shareholders' equity | 7,958 | 7,861 | ' | |||
Baltimore Gas and Electric Company [Member] | Removal Costs [Member] | ' | ' | ' | |||
Current liabilities | ' | ' | ' | |||
Regulatory liabilities | 24 | 21 | ' | |||
Deferred credits and other liabilities | ' | ' | ' | |||
Regulatory liabilities | $203 | $204 | ' | |||
[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 $) | Mar. 31, 2014 | Dec. 31, 2013 |
In Millions, except Share data, unless otherwise specified | ||
Accounts Receivable [Abstract] | ' | ' |
Gross accounts receivable pledged as collateral | $0 | $0 |
Shareholders' equity | ' | ' |
Common stock, shares authorized | 2,000,000,000 | 2,000,000,000 |
Common stock, shares outstanding | 858,721,507 | 857,000,000 |
Treasury Stock, Shares held | 35,000,000 | 35,000,000 |
PECO Energy Co [Member] | ' | ' |
Accounts Receivable [Abstract] | ' | ' |
Gross accounts receivable pledged as collateral | $0 | $0 |
Consolidated_Statement_of_Chan
Consolidated Statement of Changes in Shareholders Equity (Unaudited) (USD $) | Total | Common Stock [Member] | Treasury Stock | Retained Earnings | Accumulated Other Comprehensive (Loss) Income, Net | Noncontrolling Interest | Preference Stock Not Subject To Mandatory Redemption [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | ||
In Millions, except Share data in Thousands | Undistributed Earnings [Member] | Membership Interest [Member] | Accumulated Other Comprehensive (Loss) Income, Net | Noncontrolling Interest | Common Stock [Member] | Retained Earnings | Accumulated Other Comprehensive (Loss) Income, Net | Common Stock [Member] | Other Paid-In Capital | Retained Deficit Unappropriated | Retained Earnings Appropriated | Common Stock [Member] | Nonredeemable Preferred Stock [Member] | Retained Earnings | |||||||||||||
Beginning Balance at Dec. 31, 2013 | $22,732 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $3,065 | $2,415 | $649 | $1 | $7,528 | $1,588 | $5,190 | ($1,639) | $2,389 | $2,365 | $1,360 | $190 | $1,005 | ||
Beginning Balance at Dec. 31, 2013 | 22,940 | 16,741 | -2,327 | 10,358 | -2,040 | 15 | 193 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,555 | ' | ' | ' | ||
Beginning Balance at Dec. 31, 2013 | ' | 892,034 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Beginning Balance at Dec. 31, 2013 | ' | ' | ' | ' | ' | ' | ' | 12,742 | 3,613 | 8,898 | 214 | 17 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Net income | 93 | ' | ' | 90 | ' | ' | 3 | -185 | -185 | ' | ' | 0 | 89 | ' | 89 | ' | 98 | ' | ' | 98 | ' | 88 | ' | ' | 88 | ||
Net income on common stock | 90 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 89 | ' | ' | ' | ' | ' | ' | ' | ' | 85 | ' | ' | ' | ||
Long-term incentive plan activity | ' | 1,167 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Employee stock purchase plan issuances | ' | 265 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Appropriation of retained earnings for future dividends | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -98 | 98 | ' | ' | ' | ' | ||
Long-term incentive plan activity | 4 | 4 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Employee stock purchase plan issuances | 6 | 6 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Common stock dividends | -268 | ' | ' | -268 | ' | ' | ' | ' | ' | ' | ' | ' | -80 | ' | -80 | ' | -76 | ' | ' | ' | -76 | ' | ' | ' | ' | ||
Contribution from parent | ' | ' | ' | ' | ' | ' | ' | 0 | ' | 0 | ' | 0 | ' | ' | ' | ' | 38 | ' | 38 | ' | ' | ' | ' | ' | ' | ||
Distribution to members | ' | ' | ' | ' | ' | ' | ' | -30 | -30 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Allocation of tax benefit from members | ' | ' | ' | ' | ' | ' | ' | 0 | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Preferred stock redemption premium | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Allocation of tax benefit from parent | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | 2 | ' | ' | ' | ' | ' | ' | ||
Consolidated VIE dividend to non-controlling interest | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Preferred security dividends | -3 | ' | ' | ' | ' | ' | -3 | ' | ' | ' | ' | ' | 0 | ' | 0 | ' | ' | ' | ' | ' | ' | -3 | ' | -3 | ' | ||
Noncontrolling interest acquired | ' | ' | ' | ' | ' | -2 | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Other comprehensive income (loss), net of tax | 4 | [1] | ' | ' | ' | ' | ' | ' | -21 | [1] | ' | ' | -21 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Sale of noncontrolling interest | ' | ' | ' | ' | ' | ' | ' | 2 | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
ImpairmentOfLongLivedAssetsToBeDisposedOf | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Deconsolidation of VIE | ' | ' | ' | ' | ' | ' | ' | 0 | ' | 0 | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Ending Balance at Mar. 31, 2014 | 22,568 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,074 | 2,415 | 658 | 1 | 7,590 | 1,588 | 5,230 | -1,639 | 2,411 | 2,450 | 1,360 | 190 | 1,090 | ||
Ending Balance at Mar. 31, 2014 | 22,778 | 16,751 | -2,327 | 10,180 | -2,036 | 17 | 193 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,640 | ' | ' | ' | ||
Ending Balance at Mar. 31, 2014 | ' | 893,466 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Ending Balance at Mar. 31, 2014 | ' | ' | ' | ' | ' | ' | ' | $12,508 | $3,398 | $8,898 | $193 | $19 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
[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 | |
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Other comprehensive income, income taxes | ($6) | ($66) |
Accumulated Other Comprehensive (Loss) Income, Net | ' | ' |
Other comprehensive income, income taxes | 6 | ' |
Exelon Generation Co L L C [Member] | ' | ' |
Other comprehensive income, income taxes | 10 | 68 |
Exelon Generation Co L L C [Member] | Accumulated Other Comprehensive (Loss) Income, Net | ' | ' |
Other comprehensive income, income taxes | $10 | ' |
Basis_of_Presenation_Exelon_Ge
Basis of Presenation (Exelon, Generation, Come, PECO and BGE) | 3 Months Ended |
Mar. 31, 2014 | |
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. | |
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. | |
Each of the Registrant's Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated. | |
Certain prior year amounts in the Exelon, Generation and BGE Consolidated Statement of Operations have been reclassified between line items for comparative purposes and correction of prior period classification errors identified in 2013. The reclassifications did not affect any of the Registrants' net income or cash flows from operating activities. Exelon and Generation corrected the presentation of purchase power and fuel from affiliates of $318 million and $321 million, respectively, on their Statements of Operations and Comprehensive Income for the three months ended March 31, 2013. Generation and BGE also corrected the presentation of interest expense to affiliates, net of $17 million and $4 million, respectively, on the Statement of Operations and Comprehensive Income for the three months ended March 31, 2013. | |
The accompanying consolidated financial statements as of March 31, 2014 and 2013 and for the three 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, 2013 Consolidated Balance Sheets were obtained from audited financial statements. Financial results for interim periods are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year ending December 31, 2014. 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 2013 Form 10-K Reports. |
New_Accounting_Pronouncements_
New Accounting Pronouncements (Exelon, Generation, ComEd, PECO and BGE) | 3 Months Ended |
Mar. 31, 2014 | |
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 2014. | |
Presentation of Unrecognized Tax Benefits When Net Operating Loss Carryforwards, Similar Tax Losses or Tax Credit Carryforwards Exist | |
In July 2013, the FASB issued authoritative guidance requiring entities to present unrecognized tax benefits as a reduction to deferred tax assets for losses or other tax carryforwards that would be available to offset the uncertain tax positions at the reporting date. This guidance was effective for the Registrants for periods beginning after December 15, 2013 and was required to be applied prospectively. The Registrants did not apply this guidance retrospectively; it will be applied prospectively. The adoption of this standard had an immaterial effect on the presentation of deferred tax assets at Exelon and Generation and no effect on ComEd, PECO and BGE. There was no effect on the Registrants' results of operations or cash flows. | |
Variable_Interest_Entities_Exe
Variable Interest Entities (Exelon, Generation, ComEd, PECO and BGE) | 3 Months Ended | ||||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||||
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 affect the entity's economic performance. | |||||||||||||||||||
At March 31, 2014 and December 31, 2013, Exelon, Generation, and BGE collectively consolidated five and four VIEs or VIE groups, respectively, for which the applicable Registrant was the primary beneficiary. As of March 31, 2014 and December 31, 2013, the Registrants had significant interests in eight other VIEs for which the Registrants do not have the power to direct the entities' activities and accordingly, were not the primary beneficiary. | |||||||||||||||||||
Consolidated Variable Interest Entities | |||||||||||||||||||
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 by Generation to enter into a collateralized gas supply agreement with a third-party gas supplier; | |||||||||||||||||||
a group of solar project limited liability companies formed by Generation to build, own and operate solar power facilities, | |||||||||||||||||||
several wind project companies designed by Generation to develop, construct and operate wind generation facilities, and | |||||||||||||||||||
certain retail power companies for which Generation is the sole supplier of energy. | |||||||||||||||||||
As of March 31, 2014 and December 31, 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 months ended March 31, 2014 and 2013, BGE remitted $21 million and $22 million, respectively, to BondCo. | |||||||||||||||||||
Except for providing capital funding to the solar entities for ongoing construction of the solar power facilities, including the solar entities limited recourse to Generation with respect to the remaining equity contributions necessary to complete the Antelope Valley project, immaterial parental guarantees posted to electric distribution companies for the retail power companies, and a $75 million parental guarantee to the third-party gas supplier in support of the retail gas group, during the three months ended March 31, 2014 and year ended December 31, 2013: | |||||||||||||||||||
Exelon, Generation and BGE did not provide any additional material financial support to the VIEs; | |||||||||||||||||||
Exelon, Generation and BGE did not have any material contractual commitments or obligations to provide financial support to the VIEs; and | |||||||||||||||||||
the creditors of the VIEs did not have recourse to Exelon's, Generation's or BGE's general credit. | |||||||||||||||||||
For additional information on these project-specific financing arrangements refer to Note 8—Debt and Credit Agreements. | |||||||||||||||||||
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 March 31, 2014 and December 31, 2013 are as follows: | |||||||||||||||||||
31-Mar-14 | 31-Dec-13 | ||||||||||||||||||
Exelon (a) | Generation | BGE | Exelon (a) | Generation | BGE | ||||||||||||||
Current assets | $ | 738 | $ | 679 | $ | 53 | $ | 484 | $ | 446 | $ | 28 | |||||||
Noncurrent assets | 1,893 | 1,870 | 3 | 1,905 | 1,884 | 3 | |||||||||||||
Total assets | $ | 2,631 | $ | 2,549 | $ | 56 | $ | 2,389 | $ | 2,330 | $ | 31 | |||||||
Current liabilities | $ | 608 | $ | 525 | $ | 78 | $ | 566 | $ | 481 | $ | 74 | |||||||
Noncurrent liabilities | 780 | 566 | 195 | 774 | 562 | 195 | |||||||||||||
Total liabilities | $ | 1,388 | $ | 1,091 | $ | 273 | $ | 1,340 | $ | 1,043 | $ | 269 | |||||||
_______________________ | |||||||||||||||||||
Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity. | |||||||||||||||||||
In March 2014, Generation began consolidating retail power VIEs for which Generation is the primary beneficiary as a result of energy supply contracts that give Generation the power to direct the activities that most significantly affect the economic performance of the entities. Generation does not have an equity ownership interest in these entities. These entities are included in Generation's consolidated financial statements and the consolidation of the VIEs did not have a material impact on Generation's financial results or financial condition. | |||||||||||||||||||
On April 1, 2014, Generation, CENG, and subsidiaries of CENG executed the Nuclear Operating Services Agreement (NOSA) pursuant to which Generation now conducts all activities associated with the operations of the CENG fleet and provides corporate and administrative services to CENG for the remaining life of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to the CENG member rights of EDFI. As a result of executing the NOSA, Generation has the responsibility to conduct CENG's operating activities pursuant to contractual arrangements rather than through the equity investment; therefore CENG will qualify as a VIE in the second quarter of 2014. Further, since Generation is conducting the operational activities of CENG, Generation qualifies as the primary beneficiary of CENG and, therefore, will be required to consolidate the financial position and results of operations of CENG beginning in the second quarter of 2014. For additional information on this transaction refer to Note – 5 Investment in Constellation Energy Nuclear Group, LLC. | |||||||||||||||||||
Unconsolidated Variable Interest Entities | |||||||||||||||||||
Exelon's and Generation's variable interests in unconsolidated VIEs generally include equity investments and energy purchase and sale contracts. For the equity investments, the carrying amount of the investments is reflected on Exelon's and Generation's Consolidated Balance Sheets in Investments in affiliates, Investments, and Other Assets. For the energy purchase and sale contracts and the fuel purchase commitments (commercial agreements), the carrying amount of assets and liabilities in Exelon's and Generation's Consolidated Balance Sheets that relate to their involvement with the VIEs are predominately related to working capital accounts and generally represent the amounts owed by, or owed to, Exelon and Generation for the deliveries associated with the current billing cycles under the commercial agreements. Further, Exelon and Generation have not provided material debt or equity support, liquidity arrangements or performance guarantees associated with these commercial agreements. | |||||||||||||||||||
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. | |||||||||||||||||||
Equity investments in energy development projects and energy generating facilities for which Generation has concluded that consolidation is not required. | |||||||||||||||||||
As of March 31, 2014 and December 31, 2013, Exelon and Generation had significant unconsolidated variable interests in eight VIEs for which Exelon or Generation, as applicable, was not the primary beneficiary; including certain equity method investments and certain commercial agreements. The number of unconsolidated VIEs did not change overall, however, during the first quarter of 2014 Generation sold its ownership interest in one unconsolidated VIE and made an investment in another VIE which is unconsolidated. The following tables present summary information about Exelon and Generation's significant unconsolidated VIE entities: | |||||||||||||||||||
Commercial | Equity | ||||||||||||||||||
Agreement | Investment | ||||||||||||||||||
31-Mar-14 | VIEs | VIEs | Total | ||||||||||||||||
Total assets (a) | $ | 113 | $ | 344 | $ | 457 | |||||||||||||
Total liabilities (a) | 2 | 139 | 141 | ||||||||||||||||
Registrants' ownership interest (a) | 0 | 64 | 64 | ||||||||||||||||
Other ownership interests (a) | 111 | 143 | 254 | ||||||||||||||||
Registrants' maximum exposure to loss: | |||||||||||||||||||
Carrying amount of equity method investments | 0 | 73 | 73 | ||||||||||||||||
Contract intangible asset | 9 | 0 | 9 | ||||||||||||||||
Debt and payment guarantees | 0 | 3 | 3 | ||||||||||||||||
Net assets pledged for Zion Station decommissioning (b) | 44 | 0 | 44 | ||||||||||||||||
Commercial | Equity | ||||||||||||||||||
Agreement | Investment | ||||||||||||||||||
31-Dec-13 | VIEs | VIEs | Total | ||||||||||||||||
Total assets (a) | $ | 128 | $ | 332 | $ | 460 | |||||||||||||
Total liabilities (a) | 17 | 123 | 140 | ||||||||||||||||
Registrants' ownership interest (a) | 0 | 86 | 86 | ||||||||||||||||
Other ownership interests (a) | 111 | 123 | 234 | ||||||||||||||||
Registrants' maximum exposure to loss: | |||||||||||||||||||
Carrying amount of equity method investments | 7 | 67 | 74 | ||||||||||||||||
Contract intangible asset | 9 | 0 | 9 | ||||||||||||||||
Debt and payment guarantees | 0 | 5 | 5 | ||||||||||||||||
Net assets pledged for Zion Station decommissioning (b) | 44 | 0 | 44 | ||||||||||||||||
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 $429 million and $458 million as of March 31, 2014 and December 31, 2013, respectively; offset by payables to ZionSolutions LLC of $385 million and $414 million as of March 31, 2014 and December 31, 2013, respectively. These items are included to provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE. | |||||||||||||||||||
For each of the unconsolidated VIEs, 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 material agreements with, or commitments by, third parties that would affect the fair value or risk of their variable interests in these VIEs. | |||||||||||||||||||
Regulatory_Matters_Exelon_Gene
Regulatory Matters (Exelon, Generation, ComEd, PECO and BGE) | 3 Months Ended | |||||||||||||||||||||||||||||
Mar. 31, 2014 | ||||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ' | |||||||||||||||||||||||||||||
Regulatory Matters (Exelon, Generation, ComEd, PECO and BGE) | ' | [1] | ||||||||||||||||||||||||||||
4. 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 2013 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 annual formula rate update is based on prior year actual costs and current year projected capital additions. The update also reconciles any differences between the revenue requirement(s) in effect for the prior year and actual costs incurred for that year. 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 March 31, 2014, and December 31, 2013, ComEd had recorded a net regulatory asset associated with the distribution formula rate of $459 million and $463 million, respectively. The regulatory asset associated with the distribution true-up will be amortized as the associated amounts are recovered through rates. | ||||||||||||||||||||||||||||||
On April 16, 2014, ComEd filed its annual distribution formula rate update with the ICC. The filing establishes the revenue requirement used to set the rates that will take effect in January 2015 after the ICC's review and approval, which is due by December 2014. The revenue requirement requested is based on 2013 actual costs plus projected 2014 capital additions as well as an annual reconciliation of the revenue requirement in effect in 2013 to the actual costs incurred that year. ComEd requested a total increase to the net revenue requirement of $275 million, reflecting an increase of $177 million for the initial revenue requirement for 2014 and an increase of $98 million related to the annual reconciliation for 2013. The initial revenue requirement for 2014 provides for a weighted average debt and equity return on distribution rate base of 7.06% inclusive of an allowed return on common equity of 9.25%, reflecting the average rate on 30-year treasury notes plus 580 basis points. The annual reconciliation for 2013 provided for a weighted average debt and equity return on distribution rate base of 7.04% inclusive of an allowed return on common equity of 9.20%, reflecting the average rate on 30-year treasury notes plus 580 basis points less a performance metrics penalty of 5 basis points. | ||||||||||||||||||||||||||||||
On April 1, 2014, ComEd filed an annual progress report on its AMI Implementation Plan. On April 16, 2014, the ICC ruled that no investigation would be opened as a result of the annual filing. ComEd's current approved deployment plan provides for the installation of 4 million electric smart meters by the end of 2021. On March 13, 2014, ComEd filed a petition with the ICC for approval to accelerate the deployment of AMI Meters. If approved, the deployment plan would accelerate the projected completion of installation from 2021 to 2018. ComEd has requested that the ICC approve the proposed petition in the second quarter of 2014. | ||||||||||||||||||||||||||||||
Appeal of Initial Formula Rate Tariff (Exelon and ComEd). On March 26, 2014, the Illinois Appellate Court issued an opinion with respect to ComEd's appeal the ICC's order relating to ComEd's initial formula rate tariff. The most significant financial issues under appeal related to ICC findings that were counter to the formula rate legislation and were clarified by subsequent legislation (Senate Bill 9). Therefore, only a subset of the issues originally appealed remained. The Court found against ComEd on each of the remaining issues: compensation related adjustments, billing determinants and the use of certain allocators. The Court's opinion has no accounting impact as ComEd recorded the distribution formula regulatory asset consistent with the ICC's Final Order. | ||||||||||||||||||||||||||||||
ComEd has asked the Illinois Supreme Court to hear the issue of allocation between State and Federal regulatory jurisdictions. There is no set time by which the Court must decide whether it will hear the case. ComEd cannot predict whether the Court will elect to hear the case or, if it does, the outcome of the appeal. | ||||||||||||||||||||||||||||||
Advanced Metering Program Proceeding (Exelon and ComEd) As part of ComEd's 2007 electric distribution rate case, the ICC approved recovery of costs associated with ComEd's System Modernization Program (Rider SMP) for the limited purpose of implementing a pilot program for AMI. In October 2009, the ICC approved ComEd's AMI pilot program and associated rider (Rider AMP). ComEd collected approximately $24 million under Rider AMP and had no collections under Rider SMP through March 31, 2014. In ComEd's 2010 electric distribution rate case, the ICC approved ComEd's transfer of certain other costs from recovery under Rider AMP to recovery through electric distribution rates. | ||||||||||||||||||||||||||||||
Several parties, including the Illinois Attorney General, appealed the ICC's orders on Rider SMP and Rider AMP. The Illinois Appellate Court reversed the ICC's approval of the cost recovery provisions of Rider SMP and Rider AMP on September 30, 2010 and March 19, 2012, respectively. In both cases, the Court ruled that the ICC's approval of the rider constituted single-issue ratemaking. ComEd filed Petitions for Leave to Appeal to the Illinois Supreme Court, which were denied. | ||||||||||||||||||||||||||||||
In October 2013, the ICC opened an investigation on Rider AMP to determine if a refund is required and if so, to determine the appropriate refund amount. The ALJ presiding over the investigation requested each party provide a pre-trial memorandum describing their positions, which were submitted on April 10, 2014. The ICC Staff and the Illinois Attorney General proposed a refund of $14.6 million, representing the amount they claim was collected under Rider AMP since September 30, 2010, the date the Illinois Appellate Court reversed the ICC's approval of the cost recovery provisions of Rider SMP. ComEd believes no refund is appropriate and that any refund obligation associated with Rider AMP should be prospective from no earlier than the date of the Illinois Appellate Court's order on Rider AMP, or March 19, 2012. As a result, ComEd recorded a regulatory liability of approximately $0.4 million at March 31, 2014, which represents the amounts collected from customers since March 19, 2012. ComEd cannot predict the ultimate outcome of the ICC's investigation and therefore, actual refunds, if any, may differ from the estimated liability recorded at March 31, 2014. | ||||||||||||||||||||||||||||||
Pennsylvania Regulatory Matters | ||||||||||||||||||||||||||||||
Pennsylvania Procurement Proceedings (Exelon and PECO). 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 began in December 2013. In January 2014, PECO entered into contracts with PAPUC-approved bidders, including Generation, for its residential and small, medium, and large commercial classes that will begin in June 2014. Charges incurred for electric supply procured through contracts with Generation are included in purchased power from affiliates on PECO's Statement of Operations and Comprehensive Income. | ||||||||||||||||||||||||||||||
In addition, the second DSP Program includes a number of retail market enhancements recommended by the PAPUC in its previously issued Retail Markets Intermediate Work Plan Order. PECO was also directed to submit a plan 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. By Order entered on January 24, 2014, the PAPUC approved PECO's plan, with modifications, to make CAP shopping available beginning April 15, 2014. On March 20, 2014, low-income advocacy groups filed an appeal and emergency request for a stay with the Pennsylvania Commonwealth Court, claiming that the PAPUC-ordered CAP Shopping plan does not contain sufficient protections for low-income customers. On March 28, 2014, the Commonwealth Court issued the requested stay, pending a full review of the appeal. Pending the Commonwealth Court's review, PECO will not implement CAP Shopping. The Commonwealth Court's decision is expected in late 2014. | ||||||||||||||||||||||||||||||
On March 10, 2014, PECO filed its third DSP Program with the PAPUC. The program has a 24-month term from June 1, 2015 through May 31, 2017, and complies with electric generation procurement guidelines set forth in Act 129. A PAPUC ruling is expected in late 2014. | ||||||||||||||||||||||||||||||
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 March 31, 2014, PECO has spent $457 million and $119 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 March 31, 2014, PECO has received $197 million, including $4 million for sub-recipients, of the $200 million in reimbursements. PECO's outstanding receivable from the DOE for reimbursable costs was $3 million as of March 31, 2014, which has been recorded in Other accounts receivable, net on Exelon's and PECO's Consolidated Balance Sheets. | ||||||||||||||||||||||||||||||
On August 15, 2012, PECO suspended installation of smart meters for new customers based on a limited number of incidents involving overheating meters. Following its own internal investigation and additional scientific analysis and testing by independent experts completed after September 30, 2012, PECO announced its decision to resume meter deployment work on October 9, 2012. PECO has replaced the previously installed meters with an alternative vendor's meters. PECO is moving forward with the alternative meters during universal deployment and continues to evaluate meters from several vendors and may use more than one meter vendor during universal deployment. | ||||||||||||||||||||||||||||||
Following PECO's decision, as of October 9, 2012, PECO will no longer use the original smart meters. For the meters that will no longer be used, the accounting guidance requires that any difference between the carrying value and net realizable value be recognized in the current period's earnings, before considering potential regulatory recovery. The cost of the original meters, including installation and removal costs, owned by PECO was approximately $17 million, net of approximately $16 million of reimbursements from the DOE and approximately $2 million of depreciation. PECO requested and received approval from the DOE that the original meters continue to be allowable costs and that any settlement with the vendor will not be considered project income. In addition, PECO remains eligible for the full $200 million in SGIG funds. On August 15, 2013, PECO entered into an agreement with the original vendor, which was part of the final agreement discussed below, under which PECO transferred the original uninstalled meters to the vendor and received $12 million in return. On January 23, 2014, PECO entered a final agreement with the vendor pursuant to which PECO will be reimbursed for amounts incurred for the original meters and related installation and removal costs, via cash payments and rebates on future purchases of licenses, goods and services primarily through 2017. PECO previously had intended to seek regulatory rate recovery in a future filing with the PAPUC of amounts not recovered from the vendor. As PECO believed such costs were probable of rate recovery based on applicable case law and past precedent on reasonably and prudently incurred costs, a regulatory asset was established at the time of the removals. As of December 31, 2013, $5 million was recorded on Exelon's and PECO's Consolidated Balance Sheets. Pursuant to the January 23, 2014, vendor agreement, PECO reclassified the regulatory asset balance as a receivable, with no gain or loss impacts on future results of operations. | ||||||||||||||||||||||||||||||
Energy Efficiency Programs (Exelon and PECO). PECO's PAPUC-approved Phase I EE&C Plan had a four-year term that began on June 1, 2009 and concluded on May 31, 2013. The Phase I Plan set forth how PECO would meet the required reduction targets established by Act 129's EE&C provisions, which included a 3% reduction in electric consumption in PECO's service territory and a 4.5% reduction in PECO's annual system peak demand in the 100 hours of highest demand by May 31, 2013. | ||||||||||||||||||||||||||||||
The peak demand period ended on September 30, 2012 and PECO filed its final compliance report on Phase 1 targets with the PAPUC on November 15, 2013. On March 20, 2014, the PAPUC issued its final report stating that PECO was in full compliance with all Phase I targets. | ||||||||||||||||||||||||||||||
On November 14, 2013, the PAPUC issued a Tentative Order on Act 129 demand reduction programs which seeks comments on a proposed demand response program methodology for future Act 129 demand reduction programs as well as demand response potential and wholesale prices suppression studies. In its February 20, 2014 Final Order, the PAPUC stated that it does not expect to make a decision as to whether it will prescribe additional demand response obligations until 2015. Any decision reached would affect PECO's EE&C Plan subsequent to its Phase II Plan. | ||||||||||||||||||||||||||||||
On February 28, 2014, PECO filed a Petition for Approval to amend its EE&C Phase II Plan to continue its DLC demand reduction program for mass market customers from June 1, 2014 to May 31, 2016. PECO proposed to fund the estimated $10 million annual costs of the program by modifying incentive levels for other Phase II programs. The costs of the DLC program will be recovered through PECO's Energy Efficiency Program Charge along with other Phase II Plan costs. In an April 23, 2014 Tentative Order, the PAPUC granted PECO's Petition. Absent any filing of opposing comments by parties, the Order will become final on May 5, 2014. | ||||||||||||||||||||||||||||||
Maryland Regulatory Matters | ||||||||||||||||||||||||||||||
2013 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). On May 17, 2013, BGE filed an application for increases of $101 million and $30 million to its electric and gas base rates, respectively, with the MDPSC. The requested rates of return on equity in the application were 10.50% and 10.35% for electric and gas distribution, respectively. In addition to these requested rate increases, BGE's application also included a request for recovery of incremental capital expenditures and operating costs associated with BGE's proposed short-term reliability improvement plan (the “ERI initiative”) in response to a MDPSC order through a surcharge separate from base rates. On August 23, 2013, BGE filed an update to its rate request which altered the requested increase to electric base rates from $101 million to $83 million and the requested increase to gas base rates from $30 million to $24 million. On December 13, 2013, the MDPSC issued an order in BGE's 2013 electric and natural gas distribution rate case for increases in annual distribution service revenue of $34 million and $12 million, respectively. The electric distribution rate increase was set using an allowed return on equity of 9.75% and the gas distribution rate increase was set using an allowed return on equity of 9.60%. The approved electric and natural gas distribution rates became effective for services rendered on or after December 13, 2013. As part of its December 13, 2013 decision granting BGE increases for its gas and electric distribution rates, the MDPSC also authorized BGE to recover through a surcharge mechanism costs associated with five ERI initiative programs designed to accelerate electric reliability improvements. Such a decision, however, was premised upon the condition that the MDPSC approve specific projects scheduled for each year of the five-year program in advance of cost recovery through the surcharge mechanism. On March 31, 2014, after reviewing comments filed by the parties and conducting a hearing on the matter, the MDPSC approved all but one project proposed for completion in 2014 as part of the ERI initiative. As a result of the MDPSC's decision, BGE's estimates 2014 capital and operating and maintenance costs associated with the ERI initiative of $14.8 million and a revenue requirement of $1.4 million. The ERI initiative surcharge will become effective upon the MDPSC's approval of the revised tariff pages for the surcharge mechanism that BGE filed with the MDPSC on April 3, 2014. BGE is required to file an update on the 2014 work plan and reliability performance information for the specific projects, along with its work plan and cost estimates for 2015, on or before November 1, 2014. | ||||||||||||||||||||||||||||||
Smart Meter and Smart Grid Investments (Exelon and BGE). In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE that includes the planned installation of 2 million residential and commercial electric and gas smart meters at an expected total cost of $480 million of which $200 million has been recovered through a grant from the DOE. The MDPSC's approval ordered BGE to defer the associated incremental costs, depreciation and amortization, and an appropriate return, in a regulatory asset until such time as a cost-effective advanced metering system is implemented. As of March 31, 2014 and December 31, 2013, BGE recorded a regulatory asset of $78 million and $66 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. On February 26, 2014, the MDPSC issued an Order authorizing BGE to impose a $75 upfront fee and an $11 recurring fee to customers electing to opt-out, effective July 1, 2014. The fees authorized by the order will be reviewed after an initial 12- to 18- month period. The ultimate impact of opt-out could affect BGE's ability to demonstrate cost-effectiveness of the advanced metering system. | ||||||||||||||||||||||||||||||
Overall, BGE continues to believe the recovery of smart grid initiative costs in future rates is probable as BGE expects to be able to demonstrate that the program benefits exceed costs. | ||||||||||||||||||||||||||||||
The Maryland Strategic Infrastructure Development and Enhancement Program (Exelon and BGE). In February 2013, the Maryland General Assembly passed legislation intended to accelerate gas infrastructure replacements in Maryland by establishing a mechanism for gas companies to promptly recover reasonable and prudent costs of eligible infrastructure replacement projects separate from base rate proceedings. On May 2, 2013, the Governor of Maryland signed the legislation into law; which took effect June 1, 2013. Under the new law, following a proceeding before the MDPSC and with the MDPSC's approval of the eligible infrastructure replacement projects along with a corresponding surcharge, BGE could begin charging gas customers a monthly surcharge for infrastructure costs incurred after June 1, 2013. The legislation includes caps on the monthly surcharges to residential and non-residential customers, and would require an annual true-up of the surcharge revenues against actual expenditures. Investment levels in excess of the cap would be recoverable in a subsequent gas base rate proceeding at which time all costs for the infrastructure replacement projects would be rolled into gas distribution rates. Irrespective of the cap, BGE is required to file a gas rate case every five years under this legislation. On August 2, 2013, BGE filed its infrastructure replacement plan and associated surcharge. On January 29, 2014, the MDPSC issued a decision conditionally approving the first five years of BGE's plan and surcharge. On March 26, 2014, the Maryland PSC approved as filed BGE's proposed 2014 project list, tariff and associated surcharge amounts, with a surcharge becoming effective April 1, 2014. BGE will defer the difference between the surcharge revenues and program costs as a regulated asset or liability, which was immaterial as of March 31, 2014. | ||||||||||||||||||||||||||||||
Federal Regulatory Matters | ||||||||||||||||||||||||||||||
Transmission Formula Rate (Exelon, ComEd and BGE). ComEd's and BGE's transmission rates are each established based on a FERC-approved formula. ComEd and BGE record regulatory assets or regulatory liabilities and corresponding increases or decreases to operating revenues for any differences between the revenue requirement in effect and ComEd's and BGE's best estimate of the revenue requirement expected to be approved by the FERC for that year's reconciliation. As of March 31, 2014, and December 31, 2013, ComEd had recorded a net regulatory asset associated with the transmission formula rate of $13 million and $17 million, respectively and BGE had recorded a net regulatory asset associated with the transmission formula rate of $3 million and a net regulatory liability of $0 million, respectively. The regulatory asset associated with the transmission true-up will be amortized as the associated amounts are recovered through rates. | ||||||||||||||||||||||||||||||
On April 16, 2014, ComEd filed its annual formula rate update with the FERC. The filing establishes the revenue requirement used to set rates that will take effect in June 2014, subject to review by the FERC and other parties, which is due by November 2014. The revenue requirement is based on 2013 actual costs plus forecasted 2014 capital additions as well as an annual reconciliation of the revenue requirement in effect starting in June 2013 to the actual cost incurred in 2013. The update resulted in a revenue requirement of $524 million plus an $11 million adjustment related to the reconciliation of 2013 actual costs for a total revenue requirement of $535 million. This compares to the 2013 revenue requirement of $488 million plus a $25 million adjustment related to the reconciliation of 2012 actual costs for a total revenue requirement of $513 million. The increase in the revenue requirement was primarily driven by increased capital investment and higher operating and maintenance costs. | ||||||||||||||||||||||||||||||
ComEd's updated formula transmission rate currently provides for a weighted average debt and equity return on transmission rate base of 8.62%, inclusive of an allowed return on common equity of 11.50%, a decrease from the 8.70% average debt and equity return previously authorized. As part of the FERC-approved settlement of ComEd's 2007 transmission rate case, the rate of return on common equity is 11.50% and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%. | ||||||||||||||||||||||||||||||
On April 28, 2014, BGE filed its annual formula rate update with the FERC. The filings established the revenue requirement used to set rates that will take effect in June 2014 subject to FERC's and other parties' review which is due by October 2014. The revenue requirement is based on 2013 actual costs plus forecasted 2014 capital additions as well as an annual reconciliation of the revenue requirement in effect starting in June 2013 to the actual cost incurred in 2013. The update resulted in a revenue requirement of $167 million plus a $4 million adjustment related to the reconciliation of 2013 actual costs for a net revenue requirement of $171 million. This compares to the 2013 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. The increase in the revenue requirement is primarily driven by higher depreciation expense and an increased level of return on investment associated with a higher equity ratio and increased rate base. | ||||||||||||||||||||||||||||||
BGE's updated formula transmission rate currently provides for a weighted average debt and equity return on transmission rate base of 8.53%, an increase from the 8.35% average debt and equity return previously authorized. As part of the FERC-approved settlement of BGE's 2005 transmission rate case in 2006, the rate of return on common equity for BGE's electric transmission business for new transmission projects placed in service on and after January 1, 2006 is 11.3%, inclusive of a 50 basis point incentive for participating in PJM. | ||||||||||||||||||||||||||||||
PJM Minimum Offer Price Rule (Exelon and Generation). PJM's capacity market rules include a Minimum Offer Price Rule (MOPR) that is intended to preclude sellers from artificially suppressing the competitive price signals for generation capacity. The FERC orders approving the MOPR were upheld by the United States Court of Appeals for the Third Circuit in February 2014. | ||||||||||||||||||||||||||||||
Exelon continues to work with PJM stakeholders and through the FERC process to implement several proposed changes to the PJM tariff aimed at ensuring that capacity resources (including those with state-sanctioned subsidy contracts, excessive imported capacity resources, capacity market speculators and certain limited availability demand response resources) cannot inappropriately affect capacity auction prices in PJM. | ||||||||||||||||||||||||||||||
License Renewals (Exelon and Generation). On June 22, 2011, Generation submitted applications to the NRC to extend the operating licenses of Limerick Units 1 and 2 by 20 years. The current operating licenses for Limerick Units 1 and 2 expire in 2024 and 2029, respectively. In June 2012, the United States Court of Appeals for the DC Circuit vacated the NRC's temporary storage rule on the grounds that the NRC should have conducted a more comprehensive environmental review to support the rule. The temporary storage rule (also referred to as the “waste confidence decision”) recognizes that licensees can safely store spent nuclear fuel at nuclear plants for up to 60 years beyond the original and renewed licensed operating life of the plants and that licensing renewal decisions do not require discussion of the environmental impact of spent fuel stored on site. In August 2012, the NRC placed a hold on issuing new or renewed operating licenses that depend on the temporary storage rule until the court's decision is addressed. In September 2012, the NRC directed NRC Staff to revise the temporary storage rule which is now not expected until October 3, 2014. Generation does not expect the NRC to issue license renewals until the end of 2014, at the earliest. | ||||||||||||||||||||||||||||||
On May 29, 2013, Generation submitted applications to the NRC to extend the operating licenses of Byron Units 1 and 2 and Braidwood Units 1 and 2 by 20 years. The current operating licenses for Byron Units 1 and 2 expire in 2024 and 2026, respectively. The current operating licenses for Braidwood Units 1 and 2 expire in 2026 and 2027, respectively. Generation does not expect the NRC to issue license renewals for Byron and Braidwood until 2015 at the earliest. | ||||||||||||||||||||||||||||||
On August 29, 2012 and August 30, 2012, Generation submitted hydroelectric license applications to the FERC for 46-year licenses for the Conowingo Hydroelectric Project (Conowingo) and the Muddy Run Pumped Storage Facility Project (Muddy Run), respectively. | ||||||||||||||||||||||||||||||
The FERC extended the deadline to January 31, 2014 to file a water quality certification application pursuant to Section 401 of the Clean Water Act (CWA) with the MDE for Conowingo. Generation is working with stakeholders to resolve licensing issues, including: (1) water quality, (2) fish passage and habitat, and (3) sediment. On January 30, 2014, Exelon filed a water quality certification application pursuant to Section 401 of the CWA with MDE for Conowingo, addressing these and other issues, although Generation cannot currently predict the conditions that ultimately may be imposed. Resolution of these issues relating to Conowingo may have a material effect on Generation's results of operations and financial position through an increase in capital expenditures and operating costs. | ||||||||||||||||||||||||||||||
On August 29, 2013, Exelon filed a water quality certification application pursuant to Section 401 of the CWA with PA DEP for Muddy Run, addressing these and other issues that included certain commitments made by Generation. The financial impact associated with these commitments is estimated to be in the range of $20 million to $30 million, and will include both an increase in capital expenditures as well as an increase in operating expenses. Exelon anticipates that the PA DEP will issue the water quality certification pursuant to Section 401 of the CWA for Muddy Run in the second quarter of 2014. | ||||||||||||||||||||||||||||||
Based on the latest FERC procedural schedule, the FERC licensing process is not expected to be completed prior to the expiration of Muddy Run's current license on August 31, 2014, and the expiration of Conowingo's license on September 1, 2014. However, the stations would continue to operate under annual licenses until FERC takes action on the 46-year license applications. The stations are currently being depreciated over their useful lives, which includes the license renewal period. As of March 31, 2014, $34 million of direct costs associated with licensing efforts have been capitalized. | ||||||||||||||||||||||||||||||
Regulatory Assets and Liabilities (Exelon, ComEd, PECO and BGE) | ||||||||||||||||||||||||||||||
Exelon, ComEd, PECO and BGE 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 March 31, 2014 and December 31, 2013. For additional information on the specific regulatory assets and liabilities, refer to Note 3 – Regulatory Matters of the Exelon 2013 Form 10-K. | ||||||||||||||||||||||||||||||
31-Mar-14 | Exelon | ComEd | PECO | BGE | ||||||||||||||||||||||||||
Regulatory assets | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | ||||||||||||||||||||||
Pension and other postretirement | ||||||||||||||||||||||||||||||
benefits | $ | 218 | $ | 2,777 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | ||||||||||||||
Deferred income taxes | 14 | 1,474 | 2 | 67 | 0 | 1,333 | 12 | 74 | ||||||||||||||||||||||
AMI programs | 6 | 186 | 6 | 43 | 0 | 65 | 0 | 78 | ||||||||||||||||||||||
Under-recovered distribution service | ||||||||||||||||||||||||||||||
costs | 197 | 262 | 197 | 262 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||
Debt costs | 12 | 54 | 9 | 51 | 3 | 3 | 1 | 8 | ||||||||||||||||||||||
Fair value of BGE long-term debt (a) | 6 | 206 | 0 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||
Fair value of BGE supply contract (b) | 9 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||
Severance | 10 | 12 | 6 | 0 | 0 | 0 | 4 | 12 | ||||||||||||||||||||||
Asset retirement obligations | 1 | 108 | 1 | 72 | 0 | 25 | 0 | 11 | ||||||||||||||||||||||
MGP remediation costs | 44 | 201 | 37 | 168 | 6 | 32 | 1 | 1 | ||||||||||||||||||||||
RTO start-up costs | 2 | 0 | 2 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||
Under-recovered uncollectible | ||||||||||||||||||||||||||||||
accounts | 0 | 74 | 0 | 74 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||
Renewable energy | 13 | 155 | 13 | 155 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||
Energy and transmission programs | 51 | 0 | 50 | 0 | 1 | 0 | 0 | 0 | ||||||||||||||||||||||
Deferred storm costs | 3 | 2 | 0 | 0 | 0 | 0 | 3 | 2 | ||||||||||||||||||||||
Electric generation-related | ||||||||||||||||||||||||||||||
regulatory asset | 13 | 27 | 0 | 0 | 0 | 0 | 13 | 27 | ||||||||||||||||||||||
Rate stabilization deferral | 72 | 133 | 0 | 0 | 0 | 0 | 72 | 133 | ||||||||||||||||||||||
Energy efficiency and demand | ||||||||||||||||||||||||||||||
response programs | 57 | 146 | 0 | 0 | 0 | 0 | 57 | 146 | ||||||||||||||||||||||
Merger integration costs | 2 | 8 | 0 | 0 | 0 | 0 | 2 | 8 | ||||||||||||||||||||||
Other | 38 | 38 | 17 | 26 | 18 | 7 | 3 | 4 | ||||||||||||||||||||||
Total regulatory assets | $ | 768 | $ | 5,863 | $ | 340 | $ | 918 | $ | 28 | $ | 1,465 | $ | 168 | $ | 504 | ||||||||||||||
31-Mar-14 | Exelon | ComEd | PECO | BGE | ||||||||||||||||||||||||||
Regulatory liabilities | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | ||||||||||||||||||||||
Other postretirement benefits | $ | 2 | $ | 47 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | ||||||||||||||
Nuclear decommissioning | 0 | 2,774 | 0 | 2,319 | 0 | 455 | 0 | 0 | ||||||||||||||||||||||
Removal costs | 105 | 1,440 | 81 | 1,237 | 0 | 0 | 24 | 203 | ||||||||||||||||||||||
Energy efficiency and demand | ||||||||||||||||||||||||||||||
response programs | 40 | 0 | 39 | 0 | 1 | 0 | 0 | 0 | ||||||||||||||||||||||
DLC Program Costs | 1 | 11 | 0 | 0 | 1 | 11 | 0 | 0 | ||||||||||||||||||||||
Energy efficiency Phase 2 | 0 | 31 | 0 | 0 | 0 | 31 | 0 | 0 | ||||||||||||||||||||||
Electric distribution tax repairs | 22 | 108 | 0 | 0 | 22 | 108 | 0 | 0 | ||||||||||||||||||||||
Gas distribution tax repairs | 8 | 36 | 0 | 0 | 8 | 36 | 0 | 0 | ||||||||||||||||||||||
Energy and transmission programs | 76 | 10 | 0 | 10 | 43 | (c) | 0 | 33 | (f) | 0 | ||||||||||||||||||||
Over-recovered gas and electric | ||||||||||||||||||||||||||||||
universal service fund costs | 7 | 0 | 0 | 0 | 7 | 0 | 0 | 0 | ||||||||||||||||||||||
Revenue subject to refund (d) | 38 | 0 | 38 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||
Over-recovered gas and electric | ||||||||||||||||||||||||||||||
revenue decoupling (e) | 35 | 0 | 0 | 0 | 0 | 0 | 35 | 0 | ||||||||||||||||||||||
Other | 2 | 1 | 0 | 0 | 2 | 0 | 0 | 0 | ||||||||||||||||||||||
Total regulatory liabilities | $ | 336 | $ | 4,458 | $ | 158 | $ | 3,566 | $ | 84 | $ | 641 | $ | 92 | $ | 203 | ||||||||||||||
31-Dec-13 | Exelon | ComEd | PECO | BGE | ||||||||||||||||||||||||||
Regulatory assets | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | ||||||||||||||||||||||
Pension and other postretirement | ||||||||||||||||||||||||||||||
benefits | $ | 221 | $ | 2,794 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | ||||||||||||||
Deferred income taxes | 10 | 1,459 | 2 | 65 | 0 | 1,317 | 8 | 77 | ||||||||||||||||||||||
AMI programs | 5 | 159 | 5 | 35 | 0 | 58 | 0 | 66 | ||||||||||||||||||||||
AMI meter events | 0 | 5 | 0 | 0 | 0 | 5 | 0 | 0 | ||||||||||||||||||||||
Under-recovered distribution service | ||||||||||||||||||||||||||||||
costs | 178 | 285 | 178 | 285 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||
Debt costs | 12 | 56 | 9 | 53 | 3 | 3 | 1 | 8 | ||||||||||||||||||||||
Fair value of BGE long-term debt (a) | 0 | 219 | 0 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||
Fair value of BGE supply contract (b) | 12 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||
Severance | 16 | 12 | 12 | 0 | 0 | 0 | 4 | 12 | ||||||||||||||||||||||
Asset retirement obligations | 1 | 102 | 1 | 67 | 0 | 25 | 0 | 10 | ||||||||||||||||||||||
MGP remediation costs | 40 | 212 | 33 | 178 | 6 | 33 | 1 | 1 | ||||||||||||||||||||||
RTO start-up costs | 2 | 0 | 2 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||
Under-recovered uncollectible | ||||||||||||||||||||||||||||||
accounts | 0 | 48 | 0 | 48 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||
Renewable energy | 17 | 176 | 17 | 176 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||
Energy and transmission programs | 53 | 0 | 52 | 0 | 0 | 0 | 1 | (f) | 0 | |||||||||||||||||||||
Deferred storm costs | 3 | 3 | 0 | 0 | 0 | 0 | 3 | 3 | ||||||||||||||||||||||
Electric generation-related | ||||||||||||||||||||||||||||||
regulatory asset | 13 | 30 | 0 | 0 | 0 | 0 | 13 | 30 | ||||||||||||||||||||||
Rate stabilization deferral | 71 | 154 | 0 | 0 | 0 | 0 | 71 | 154 | ||||||||||||||||||||||
Energy efficiency and demand | ||||||||||||||||||||||||||||||
response programs | 73 | 148 | 0 | 0 | 0 | 0 | 73 | 148 | ||||||||||||||||||||||
Merger integration costs | 2 | 9 | 0 | 0 | 0 | 0 | 2 | 9 | ||||||||||||||||||||||
Other | 31 | 39 | 18 | 26 | 8 | 7 | 4 | 6 | ||||||||||||||||||||||
Total regulatory assets | $ | 760 | $ | 5,910 | $ | 329 | $ | 933 | $ | 17 | $ | 1,448 | $ | 181 | $ | 524 | ||||||||||||||
31-Dec-13 | Exelon | ComEd | PECO | BGE | ||||||||||||||||||||||||||
Regulatory liabilities | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | ||||||||||||||||||||||
Other postretirement benefits | $ | 2 | $ | 43 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | ||||||||||||||
Nuclear decommissioning | 0 | 2,740 | 0 | 2,293 | 0 | 447 | 0 | 0 | ||||||||||||||||||||||
Removal costs | 99 | 1,423 | 78 | 1,219 | 0 | 0 | 21 | 204 | ||||||||||||||||||||||
Energy efficiency and demand | ||||||||||||||||||||||||||||||
response programs | 53 | 0 | 45 | 0 | 8 | 0 | 0 | 0 | ||||||||||||||||||||||
DLC Program Costs | 1 | 10 | 0 | 0 | 1 | 10 | 0 | 0 | ||||||||||||||||||||||
Energy efficiency phase II | 0 | 21 | 0 | 0 | 0 | 21 | 0 | 0 | ||||||||||||||||||||||
Electric distribution tax repairs | 20 | 114 | 0 | 0 | 20 | 114 | 0 | 0 | ||||||||||||||||||||||
Gas distribution tax repairs | 8 | 37 | 0 | 0 | 8 | 37 | ||||||||||||||||||||||||
Energy and transmission programs | 78 | 0 | 9 | 0 | 58 | (c) | 0 | 11 | (f) | 0 | ||||||||||||||||||||
Over-recovered gas and electric | ||||||||||||||||||||||||||||||
universal service fund costs | 8 | 0 | 0 | 0 | 8 | 0 | 0 | 0 | ||||||||||||||||||||||
Revenue subject to refund (d) | 38 | 0 | 38 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||
Over-recovered electric and gas | ||||||||||||||||||||||||||||||
revenue decoupling (e) | 16 | 0 | 0 | 0 | 0 | 0 | 16 | 0 | ||||||||||||||||||||||
Other | 4 | 0 | 0 | 0 | 3 | 0 | 0 | 0 | ||||||||||||||||||||||
Total regulatory liabilities | $ | 327 | $ | 4,388 | $ | 170 | $ | 3,512 | $ | 106 | $ | 629 | $ | 48 | $ | 204 | ||||||||||||||
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 8 – 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. | ||||||||||||||||||||||||||||||
Includes $32 million related to the DSP program, $0 million related to the over-recovered natural gas costs under the PGC and $11 million related to over-recovered electric transmission costs as of March 31, 2014. As of December 31, 2013, includes $34 million related to the DSP program, $8 million related to the over-recovered electric transmission costs and $16 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 Note 3 – Regulatory Matters of the Exelon 2013 Form 10-K. for further information. | ||||||||||||||||||||||||||||||
Represents the electric and gas distribution costs recoverable from customers under BGE's decoupling mechanism. As of March 31, 2014, BGE had a regulatory liability of $14 million related to over-recovered electric revenue decoupling and $21 million related to over-recovered natural gas revenue decoupling. As of December 31, 2013, BGE had a regulatory liability of $7 million related to over-recovered electric revenue decoupling and $9 million related to over-recovered natural gas revenue decoupling. | ||||||||||||||||||||||||||||||
Relates to $3 million of over-recovered electric supply costs and $30 million of over-recovered natural gas supply costs as of March 31, 2014. As of December 31, 2013, includes $1 million of under-recovered electric supply costs and $11 million of over-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 March 31, 2014 and December 31, 2013. | ||||||||||||||||||||||||||||||
As of March 31, 2014 | Exelon | ComEd | PECO | BGE | ||||||||||||||||||||||||||
Purchased receivables (a) | $ | 330 | $ | 125 | $ | 93 | $ | 112 | ||||||||||||||||||||||
Allowance for uncollectible accounts (b) | -36 | -19 | -10 | -7 | ||||||||||||||||||||||||||
Purchased receivables, net | $ | 294 | $ | 106 | $ | 83 | $ | 105 | ||||||||||||||||||||||
As of December 31, 2013 | Exelon | ComEd | PECO | BGE | ||||||||||||||||||||||||||
Purchased receivables (a) | $ | 263 | $ | 105 | $ | 72 | $ | 86 | ||||||||||||||||||||||
Allowance for uncollectible accounts (b) | -30 | -16 | -7 | -7 | ||||||||||||||||||||||||||
Purchased receivables, net | $ | 233 | $ | 89 | $ | 65 | $ | 79 | ||||||||||||||||||||||
__________ | ||||||||||||||||||||||||||||||
(a) PECO's gas POR program became effective on January 1, 2012 and includes a 1% discount on purchased receivables in order to recover the implementation costs of the program. If the costs are not fully recovered when PECO files its next gas distribution rate case, PECO will propose a mechanism to recover the remaining implementation costs as a distribution charge to low volume transportation customers or apply future discounts on purchased receivables from natural gas suppliers serving those customers. | ||||||||||||||||||||||||||||||
(b) For ComEd and BGE, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through its Purchase of Receivables with Consolidated Billing (PORCB) tariff. | ||||||||||||||||||||||||||||||
[1] | Primarily represents the regulatory liability for revenue subject to refund recorded pursuant to the ICCbs order in the 2007 Rate Case. See Note 3 b Regulatory Matters of the Exelon 2013 Form 10-K. for further information. |
Investment_in_Constellation_En
Investment in Constellation Energy Nuclear Group, LLC (Exelon and Generation) | 3 Months Ended | ||||||
Mar. 31, 2014 | |||||||
Equity Method Investments and Joint Ventures [Line Items] | ' | ||||||
Investment in Constellation Energy Nuclear Group, LLC (Exelon and Generation) | ' | ||||||
5. Investment in Constellation Energy Nuclear Group, LLC (Exelon and Generation) | |||||||
As a result of the Constellation merger, Generation owns a 50.01% interest in CENG, a nuclear generation business, which is accounted for as an equity method investment as of March 31, 2014. Generation's total equity in earnings (losses) on the investment in CENG is as follows: | |||||||
Three Months | Three Months | ||||||
Ended March 31, | Ended March 31, | ||||||
2014 | 2013 | ||||||
Equity investment income | $ | -2 | $ | 15 | |||
Amortization of basis difference in CENG | -17 | -27 | |||||
Total equity in earnings - CENG | $ | -19 | $ | -12 | |||
As of March 12, 2012, Generation had an initial basis difference of approximately $204 million between the initial carrying value of its investment in CENG and its underlying equity in CENG. This basis difference resulted from the requirement to record the investment in CENG at fair value under purchase accounting while the underlying assets and liabilities within CENG continue to be accounted for on a historical cost basis. Generation is amortizing this basis difference over the respective useful lives of the assets and liabilities of CENG or as those assets and liabilities affect the earnings of CENG. | |||||||
Based on tax sharing provisions contained in the operating agreement for CENG, Generation may be eligible for distributions from its investment in CENG in excess of its 50.01% ownership interest. Through purchase accounting, Generation has recorded the fair value of expected future distributions. When these distributions are realized, Generation will record a reduction in its investment in CENG. Any distributions in excess of Generation's investment in CENG would be recorded in earnings. | |||||||
Generation has various agreements with CENG to purchase power and to provide certain services. For further information regarding these agreements see Note 25 – Related Party Transactions of the Exelon 2013 Form 10-K. | |||||||
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 closed on April 1, 2014, and, as contemplated therein, the parties executed a series of additional agreements. | |||||||
Under the Master Agreement, CENG made two pre-closing cash distributions to EDF and Generation. Generation received the distributions of $115 million and $13 million in December 2013 and March 2014, respectively, each of which was recorded as a reduction to the Investment in CENG on Exelon's and Generation's Consolidated Balance Sheets. | |||||||
At the closing, Generation, CENG and subsidiaries of CENG executed a Nuclear Operating Services Agreement (NOSA) pursuant to which Generation will operate the CENG nuclear generation fleet owned by CENG subsidiaries and provide corporate and administrative services for the remaining life of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to EDFI's rights as a member of CENG. CENG will reimburse Generation for its direct and allocated costs for such services. | |||||||
In addition, at closing, Generation made a $400 million loan to CENG, bearing interest at 5.25% per annum and payable out of specified available cash flows of CENG and, in any event, payable upon the settlement of the Put Option Agreement discussed below (if the put option is exercised) or payable upon the maturity date of April 1, 2034, whichever occurs first. Immediately following receipt of the proceeds of such loan, CENG made a $400 million special distribution to EDFI. The parties also executed a Fourth Amended and Restated Operating Agreement for CENG, pursuant to which, among other things, CENG committed 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 also entered into a Put Option Agreement at closing pursuant to which EDFI has the option, exercisable beginning on January 1, 2016 and thereafter until June 30, 2022, to sell its 49.99% interest in CENG to Generation for a fair market value price determined by agreement of the parties, or absent agreement, a third-party arbitration process. The appraisers determining fair market value of EDF's 49.99% interest in CENG under the Put Option Agreement are instructed to take into account all rights and obligations under the CENG Operating Agreement, including Generation's rights with respect to any unpaid aggregate preferred distributions and the related return, and the value of Generation's rights to other distributions. The beginning of the exercise period will be accelerated if Exelon's affiliates cease to own a majority of CENG and exercise a related right to terminate the NOSA. In addition, under limited circumstances, the period for exercise of the put option may be extended for 18 months. | |||||||
Also at closing, Generation executed an Indemnity Agreement pursuant to which Generation indemnified EDF and its affiliates against third-party claims that may arise from any future nuclear incident (as defined in the Price Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation's obligations under this indemnity. | |||||||
In addition to the agreements contemplated in the Master Agreement, on April 1, 2014, Generation, EDFI, CENG and Nine Mile Point Nuclear Station, LLC entered into an Employee Matters Agreement (EMA) that provides for the transfer of CENG employees to the Generation Parties (Generation or one of its affiliates) and the assumption of the employee benefit plans and their related trusts by the Generation Parties as the plan sponsor as of August 1, 2014 or such other date as agreed to by Generation and EDFI (the Effective Date). The EMA also generally requires CENG to fund the underfunded balance of the pension and post-retirement welfare benefit plans as of the Effective Date on an agreed payment schedule (or upon the occurrence of certain specified events, such as EDF's disposition of a majority of its interest in CENG prior to completion of scheduled payments). | |||||||
As a condition to obtaining regulatory approval for the transaction from the Nuclear Regulatory Commission, Exelon executed a Support Agreement pursuant to which Exelon may be required under specified circumstances to provide up to $245 million of financial support to the CENG plants. The Exelon Support Agreement was provided in substitution for a previous support agreement under which Generation had agreed to provide up to $205 million of financial support for CENG. In addition, Exelon executed a Guarantee pursuant to which Exelon may be required under specified circumstances to provide up to $165 million in additional financial support for the CENG plants. A previous Support Agreement executed by an affiliate of EDF remains in effect; under this Support Agreement the EDF affiliate may be required to provide up to approximately $145 million of financial support for the CENG plants under specified circumstances. | |||||||
Due to changes in energy prices, discount rates and other factors, Exelon and Generation evaluated and determined that no impairment of the investment in CENG existed as of March 31, 2014. In addition, due to the transfer of the operating licenses and the execution of the NOSA on April 1, 2014, Exelon and Generation will derecognize their equity method investment in CENG and record all assets, liabilities and EDF's non-controlling interest in CENG at fair value on Exelon and Generation's balance sheets. Any difference between the carrying value of the investment in CENG and the newly recorded fair value will be recognized as a gain or loss upon consolidation in the second quarter of 2014, which could be material to Exelon's and Generation's results of operations. See Note 3 – Variable Interest Entities for further information regarding the consolidation of CENG beginning in the second quarter of 2014. | |||||||
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) | ' | ||||||
5. Investment in Constellation Energy Nuclear Group, LLC (Exelon and Generation) | |||||||
As a result of the Constellation merger, Generation owns a 50.01% interest in CENG, a nuclear generation business, which is accounted for as an equity method investment as of March 31, 2014. Generation's total equity in earnings (losses) on the investment in CENG is as follows: | |||||||
Three Months | Three Months | ||||||
Ended March 31, | Ended March 31, | ||||||
2014 | 2013 | ||||||
Equity investment income | $ | -2 | $ | 15 | |||
Amortization of basis difference in CENG | -17 | -27 | |||||
Total equity in earnings - CENG | $ | -19 | $ | -12 | |||
As of March 12, 2012, Generation had an initial basis difference of approximately $204 million between the initial carrying value of its investment in CENG and its underlying equity in CENG. This basis difference resulted from the requirement to record the investment in CENG at fair value under purchase accounting while the underlying assets and liabilities within CENG continue to be accounted for on a historical cost basis. Generation is amortizing this basis difference over the respective useful lives of the assets and liabilities of CENG or as those assets and liabilities affect the earnings of CENG. | |||||||
Based on tax sharing provisions contained in the operating agreement for CENG, Generation may be eligible for distributions from its investment in CENG in excess of its 50.01% ownership interest. Through purchase accounting, Generation has recorded the fair value of expected future distributions. When these distributions are realized, Generation will record a reduction in its investment in CENG. Any distributions in excess of Generation's investment in CENG would be recorded in earnings. | |||||||
Generation has various agreements with CENG to purchase power and to provide certain services. For further information regarding these agreements see Note 25 – Related Party Transactions of the Exelon 2013 Form 10-K. | |||||||
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 closed on April 1, 2014, and, as contemplated therein, the parties executed a series of additional agreements. | |||||||
Under the Master Agreement, CENG made two pre-closing cash distributions to EDF and Generation. Generation received the distributions of $115 million and $13 million in December 2013 and March 2014, respectively, each of which was recorded as a reduction to the Investment in CENG on Exelon's and Generation's Consolidated Balance Sheets. | |||||||
At the closing, Generation, CENG and subsidiaries of CENG executed a Nuclear Operating Services Agreement (NOSA) pursuant to which Generation will operate the CENG nuclear generation fleet owned by CENG subsidiaries and provide corporate and administrative services for the remaining life of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to EDFI's rights as a member of CENG. CENG will reimburse Generation for its direct and allocated costs for such services. | |||||||
In addition, at closing, Generation made a $400 million loan to CENG, bearing interest at 5.25% per annum and payable out of specified available cash flows of CENG and, in any event, payable upon the settlement of the Put Option Agreement discussed below (if the put option is exercised) or payable upon the maturity date of April 1, 2034, whichever occurs first. Immediately following receipt of the proceeds of such loan, CENG made a $400 million special distribution to EDFI. The parties also executed a Fourth Amended and Restated Operating Agreement for CENG, pursuant to which, among other things, CENG committed 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 also entered into a Put Option Agreement at closing pursuant to which EDFI has the option, exercisable beginning on January 1, 2016 and thereafter until June 30, 2022, to sell its 49.99% interest in CENG to Generation for a fair market value price determined by agreement of the parties, or absent agreement, a third-party arbitration process. The appraisers determining fair market value of EDF's 49.99% interest in CENG under the Put Option Agreement are instructed to take into account all rights and obligations under the CENG Operating Agreement, including Generation's rights with respect to any unpaid aggregate preferred distributions and the related return, and the value of Generation's rights to other distributions. The beginning of the exercise period will be accelerated if Exelon's affiliates cease to own a majority of CENG and exercise a related right to terminate the NOSA. In addition, under limited circumstances, the period for exercise of the put option may be extended for 18 months. | |||||||
Also at closing, Generation executed an Indemnity Agreement pursuant to which Generation indemnified EDF and its affiliates against third-party claims that may arise from any future nuclear incident (as defined in the Price Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation's obligations under this indemnity. | |||||||
In addition to the agreements contemplated in the Master Agreement, on April 1, 2014, Generation, EDFI, CENG and Nine Mile Point Nuclear Station, LLC entered into an Employee Matters Agreement (EMA) that provides for the transfer of CENG employees to the Generation Parties (Generation or one of its affiliates) and the assumption of the employee benefit plans and their related trusts by the Generation Parties as the plan sponsor as of August 1, 2014 or such other date as agreed to by Generation and EDFI (the Effective Date). The EMA also generally requires CENG to fund the underfunded balance of the pension and post-retirement welfare benefit plans as of the Effective Date on an agreed payment schedule (or upon the occurrence of certain specified events, such as EDF's disposition of a majority of its interest in CENG prior to completion of scheduled payments). | |||||||
As a condition to obtaining regulatory approval for the transaction from the Nuclear Regulatory Commission, Exelon executed a Support Agreement pursuant to which Exelon may be required under specified circumstances to provide up to $245 million of financial support to the CENG plants. The Exelon Support Agreement was provided in substitution for a previous support agreement under which Generation had agreed to provide up to $205 million of financial support for CENG. In addition, Exelon executed a Guarantee pursuant to which Exelon may be required under specified circumstances to provide up to $165 million in additional financial support for the CENG plants. A previous Support Agreement executed by an affiliate of EDF remains in effect; under this Support Agreement the EDF affiliate may be required to provide up to approximately $145 million of financial support for the CENG plants under specified circumstances. | |||||||
Due to changes in energy prices, discount rates and other factors, Exelon and Generation evaluated and determined that no impairment of the investment in CENG existed as of March 31, 2014. In addition, due to the transfer of the operating licenses and the execution of the NOSA on April 1, 2014, Exelon and Generation will derecognize their equity method investment in CENG and record all assets, liabilities and EDF's non-controlling interest in CENG at fair value on Exelon and Generation's balance sheets. Any difference between the carrying value of the investment in CENG and the newly recorded fair value will be recognized as a gain or loss upon consolidation in the second quarter of 2014, which could be material to Exelon's and Generation's results of operations. See Note 3 – Variable Interest Entities for further information regarding the consolidation of CENG beginning in the second quarter of 2014. |
Fair_Value_of_Financial_Assets
Fair Value of Financial Assets and Liabilities (Exelon, Generation, ComEd, PECO and BGE) | 3 Months Ended | ||||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||||
Fair Value of Financial Assets and Liabilities [Line items] | ' | ||||||||||||||||||
Fair Value Disclosures [Text Block] | ' | ||||||||||||||||||
6. Fair Value of Financial Assets and Liabilities (Exelon, Generation, ComEd, PECO and BGE) | |||||||||||||||||||
Fair Value of Financial Liabilities Recorded at the Carrying Amount | |||||||||||||||||||
The following tables present the carrying amounts and fair values of the Registrants' short-term liabilities, long-term debt, SNF obligation, and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) as of March 31, 2014 and December 31, 2013: | |||||||||||||||||||
Exelon | |||||||||||||||||||
31-Mar-14 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Short-term liabilities | $ | 983 | $ | 3 | $ | 980 | $ | 0 | $ | 983 | |||||||||
Long-term debt (including amounts due within one year) | 18,920 | 0 | 18,976 | 1,066 | 20,042 | ||||||||||||||
Long-term debt to financing trusts | 648 | 0 | 0 | 648 | 648 | ||||||||||||||
SNF obligation | 1,021 | 0 | 840 | 0 | 840 | ||||||||||||||
31-Dec-13 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Short-term liabilities | $ | 344 | $ | 3 | $ | 341 | $ | 0 | $ | 344 | |||||||||
Long-term debt (including amounts due within one year) | 19,132 | 0 | 18,672 | 1,079 | 19,751 | ||||||||||||||
Long-term debt to financing trusts | 648 | 0 | 0 | 631 | 631 | ||||||||||||||
SNF obligation | 1,021 | 0 | 790 | 0 | 790 | ||||||||||||||
Generation | |||||||||||||||||||
31-Mar-14 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Short-term liabilities | $ | 377 | $ | 0 | $ | 377 | $ | 0 | $ | 377 | |||||||||
Long-term debt (including amounts due within one year) | 7,490 | 0 | 6,684 | 1,066 | 7,750 | ||||||||||||||
SNF obligation | 1,021 | 0 | 840 | 0 | 840 | ||||||||||||||
31-Dec-13 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Short-term liabilities | $ | 22 | $ | 0 | $ | 22 | $ | 0 | $ | 22 | |||||||||
Long-term debt (including amounts due within one year) | 7,729 | $ | 0 | 6,586 | 1,062 | 7,648 | |||||||||||||
SNF obligation | 1,021 | 0 | 790 | 0 | 790 | ||||||||||||||
ComEd | |||||||||||||||||||
31-Mar-14 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Short-term liabilities | $ | 534 | $ | 0 | $ | 534 | $ | 0 | $ | 534 | |||||||||
Long-term debt (including amounts due within one year) | 5,707 | 0 | 6,347 | 0 | 6,347 | ||||||||||||||
Long-term debt to financing trust | 206 | 0 | 0 | 202 | 202 | ||||||||||||||
31-Dec-13 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Short-term liabilities | $ | 184 | $ | 0 | $ | 184 | $ | 0 | $ | 184 | |||||||||
Long-term debt (including amounts due within one year) | 5,675 | 0 | 6,238 | 17 | 6,255 | ||||||||||||||
Long-term debt to financing trust | 206 | 0 | 0 | 202 | 202 | ||||||||||||||
PECO | |||||||||||||||||||
31-Mar-14 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Long-term debt (including amounts due within one year) | $ | 2,197 | $ | 0 | $ | 2,392 | $ | 0 | $ | 2,392 | |||||||||
Long-term debt to financing trusts | 184 | 0 | 0 | 190 | 190 | ||||||||||||||
31-Dec-13 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Long-term debt (including amounts due within one year) | 2,197 | 0 | 2,358 | 0 | 2,358 | ||||||||||||||
Long-term debt to financing trusts | 184 | 0 | 0 | 180 | 180 | ||||||||||||||
BGE | |||||||||||||||||||
31-Mar-14 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Short-term liabilities | $ | 72 | $ | 3 | $ | 69 | $ | 0 | $ | 72 | |||||||||
Long-term debt (including amounts due within one year) | 2,011 | 0 | 2,183 | 0 | 2,183 | ||||||||||||||
Long-term debt to financing trusts | 258 | 0 | 0 | 256 | 256 | ||||||||||||||
31-Dec-13 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Short-term liabilities | $ | 138 | $ | 3 | $ | 135 | $ | 0 | $ | 138 | |||||||||
Long-term debt (including amounts due within one year) | 2,011 | 0 | 2,148 | 0 | 2,148 | ||||||||||||||
Long-term debt to financing trusts | 258 | 0 | 0 | 249 | 249 | ||||||||||||||
Short-Term Liabilities. The short-term liabilities included in the tables above are comprised of short-term borrowings (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. | |||||||||||||||||||
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. | |||||||||||||||||||
Recurring Fair Value Measurements | |||||||||||||||||||
Exelon records the fair value of assets and liabilities in accordance with the hierarchy established by the authoritative guidance for fair value measurements. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows: | |||||||||||||||||||
Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to access as of the reporting date. Financial assets and liabilities utilizing Level 1 inputs include active exchange-traded equity securities and funds, certain exchange-based derivatives, and money market funds. | |||||||||||||||||||
Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data. Financial assets and liabilities utilizing Level 2 inputs include fixed income securities, derivatives, commingled and mutual investment funds priced at NAV per fund share and fair value hedges. | |||||||||||||||||||
Level 3 — unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability. Financial assets and liabilities utilizing Level 3 inputs include infrequently traded securities and derivatives, and investments priced using an alternative pricing mechanism or third party valuation. | |||||||||||||||||||
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. There were no transfers between Level 1 and Level 2 during the three months ended March 31, 2014 for cash equivalents, nuclear decommissioning trust fund investments, pledged assets for Zion Station decommissioning, Rabbi trust investments, and deferred compensation obligations. | |||||||||||||||||||
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 March 31, 2014 and December 31, 2013: | |||||||||||||||||||
As of March 31, 2014 | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Assets | |||||||||||||||||||
Cash equivalents(a) | $ | 518 | $ | 0 | $ | 0 | $ | 518 | |||||||||||
Nuclear decommissioning trust fund investments | |||||||||||||||||||
Cash equivalents | 304 | 0 | 0 | 304 | |||||||||||||||
Equity | |||||||||||||||||||
Individually held | 1,813 | 0 | 0 | 1,813 | |||||||||||||||
Exchange traded funds | 113 | 0 | 0 | 113 | |||||||||||||||
Commingled funds | 0 | 2,053 | 0 | 2,053 | |||||||||||||||
Equity funds subtotal | 1,926 | 2,053 | 0 | 3,979 | |||||||||||||||
Fixed income | |||||||||||||||||||
Debt securities issued by the U.S. Treasury and other | |||||||||||||||||||
U.S. government corporations and agencies | 903 | 0 | 0 | 903 | |||||||||||||||
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 | 87 | 0 | 87 | |||||||||||||||
Corporate debt securities | 0 | 1,795 | 126 | 1,921 | |||||||||||||||
Federal agency mortgage-backed securities | 0 | 9 | 0 | 9 | |||||||||||||||
Commercial mortgage-backed securities (non-agency) | 0 | 40 | 0 | 40 | |||||||||||||||
Residential mortgage-backed securities (non-agency) | 0 | 7 | 0 | 7 | |||||||||||||||
Mutual funds | 0 | 278 | 0 | 278 | |||||||||||||||
Fixed income subtotal | 903 | 2,511 | 126 | 3,540 | |||||||||||||||
Middle market lending | 0 | 0 | 356 | 356 | |||||||||||||||
Private Equity | 0 | 0 | 4 | 4 | |||||||||||||||
Other debt obligations | 0 | 15 | 0 | 15 | |||||||||||||||
Nuclear decommissioning trust fund investments subtotal(b) | 3,133 | 4,579 | 486 | 8,198 | |||||||||||||||
Pledged assets for Zion Station decommissioning | |||||||||||||||||||
Cash equivalents | 0 | 35 | 0 | 35 | |||||||||||||||
Equity | |||||||||||||||||||
Individually held | 4 | 1 | 0 | 5 | |||||||||||||||
Equity funds subtotal | 4 | 1 | 0 | 5 | |||||||||||||||
Fixed income | |||||||||||||||||||
Debt securities issued by the U.S. Treasury and other | |||||||||||||||||||
U.S. government corporations and agencies | 36 | 4 | 0 | 40 | |||||||||||||||
Debt securities issued by states of the United States | |||||||||||||||||||
and political subdivisions of the states | 0 | 18 | 0 | 18 | |||||||||||||||
Corporate debt securities | 0 | 180 | 0 | 180 | |||||||||||||||
Fixed income subtotal | 36 | 202 | 0 | 238 | |||||||||||||||
Middle market lending | 0 | 0 | 137 | 137 | |||||||||||||||
Pledged assets for Zion Station decommissioning subtotal(c) | 40 | 238 | 137 | 415 | |||||||||||||||
Rabbi trust investments | |||||||||||||||||||
Cash equivalents | 2 | 0 | 0 | 2 | |||||||||||||||
Mutual funds(d)(e) | 42 | 0 | 0 | 42 | |||||||||||||||
Rabbi trust investments subtotal | 44 | 0 | 0 | 44 | |||||||||||||||
Commodity derivative assets | |||||||||||||||||||
Economic hedges | 592 | 2,778 | 1,271 | 4,641 | |||||||||||||||
Proprietary trading | 354 | 808 | 179 | 1,341 | |||||||||||||||
Effect of netting and allocation of collateral(f) | -826 | -2,957 | -911 | -4,694 | |||||||||||||||
Commodity derivative assets subtotal | 120 | 629 | 539 | 1,288 | |||||||||||||||
Interest rate and foreign currency derivative assets | 24 | 37 | 0 | 61 | |||||||||||||||
Effect of netting and allocation of collateral | -18 | -4 | 0 | -22 | |||||||||||||||
Interest rate and foreign currency derivative assets subtotal | 6 | 33 | 0 | 39 | |||||||||||||||
Other investments | 13 | 0 | 10 | 23 | |||||||||||||||
Total assets | 3,874 | 5,479 | 1,172 | 10,525 | |||||||||||||||
Liabilities | |||||||||||||||||||
Commodity derivative liabilities | |||||||||||||||||||
Economic hedges | -586 | -2,624 | -1,253 | -4,463 | |||||||||||||||
Proprietary trading | -357 | -765 | -196 | -1,318 | |||||||||||||||
Effect of netting and allocation of collateral(f) | 943 | 3,289 | 1,029 | 5,261 | |||||||||||||||
Commodity derivative liabilities subtotal | 0 | -100 | -420 | -520 | |||||||||||||||
Interest rate and foreign currency derivative liabilities | -25 | -21 | 0 | 0 | -46 | ||||||||||||||
Effect of netting and allocation of collateral | 25 | 3 | 0 | 28 | |||||||||||||||
Interest rate and foreign currency derivative liabilities subtotal | 0 | -18 | 0 | -18 | |||||||||||||||
Deferred compensation obligation | 0 | -107 | 0 | -107 | |||||||||||||||
Total liabilities | 0 | -225 | -420 | -645 | |||||||||||||||
Total net assets | $ | 3,874 | $ | 5,254 | $ | 752 | $ | 9,880 | |||||||||||
As of December 31, 2013 | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Assets | |||||||||||||||||||
Cash equivalents(a) | $ | 1,230 | $ | 0 | $ | 0 | $ | 1,230 | |||||||||||
Nuclear decommissioning trust fund investments | |||||||||||||||||||
Cash equivalents | 459 | 0 | 0 | 459 | |||||||||||||||
Equity | |||||||||||||||||||
Individually held | 1,776 | 0 | 0 | 1,776 | |||||||||||||||
Exchange traded funds | 115 | 0 | 0 | 115 | |||||||||||||||
Commingled funds | 0 | 2,271 | 0 | 2,271 | |||||||||||||||
Equity funds subtotal | 1,891 | 2,271 | 0 | 4,162 | |||||||||||||||
Fixed income | |||||||||||||||||||
Debt securities issued by the U.S. Treasury and other | |||||||||||||||||||
U.S. government corporations and agencies | 882 | 0 | 0 | 882 | |||||||||||||||
Debt securities issued by states of the United States | |||||||||||||||||||
and political subdivisions of the states | 0 | 294 | 0 | 294 | |||||||||||||||
Debt securities issued by foreign governments | 0 | 87 | 0 | 87 | |||||||||||||||
Corporate debt securities | 0 | 1,753 | 31 | 1,784 | |||||||||||||||
Federal agency mortgage-backed securities | 0 | 10 | 0 | 10 | |||||||||||||||
Commercial mortgage-backed securities (non-agency) | 0 | 40 | 0 | 40 | |||||||||||||||
Residential mortgage-backed securities (non-agency) | 0 | 7 | 0 | 7 | |||||||||||||||
Mutual funds | 0 | 18 | 0 | 18 | |||||||||||||||
Fixed income subtotal | 882 | 2,209 | 31 | 3,122 | |||||||||||||||
Middle market lending | 0 | 0 | 314 | 314 | |||||||||||||||
Private Equity | 0 | 0 | 5 | 5 | |||||||||||||||
Other debt obligations | 0 | 14 | 0 | 14 | |||||||||||||||
Nuclear decommissioning trust fund investments subtotal(b) | 3,232 | 4,494 | 350 | 8,076 | |||||||||||||||
Pledged assets for Zion decommissioning | |||||||||||||||||||
Cash equivalents | 0 | 26 | 0 | 26 | |||||||||||||||
Equity | |||||||||||||||||||
Individually held | 16 | 0 | 0 | 16 | |||||||||||||||
Equity funds subtotal | 16 | 0 | 0 | 16 | |||||||||||||||
Fixed income | |||||||||||||||||||
Debt securities issued by the U.S. Treasury and other | |||||||||||||||||||
U.S. government corporations and agencies | 45 | 4 | 0 | 49 | |||||||||||||||
Debt securities issued by states of the United States | |||||||||||||||||||
and political subdivisions of the states | 0 | 20 | 0 | 20 | |||||||||||||||
Corporate debt securities | 0 | 227 | 0 | 227 | |||||||||||||||
Fixed income subtotal | 45 | 251 | 0 | 296 | |||||||||||||||
Middle market lending | 0 | 0 | 112 | 112 | |||||||||||||||
Other debt obligations | 0 | 1 | 0 | 1 | |||||||||||||||
Pledged assets for Zion Station decommissioning subtotal(c) | 61 | 278 | 112 | 451 | |||||||||||||||
Rabbi trust investments | |||||||||||||||||||
Cash equivalents | 2 | 0 | 0 | 2 | |||||||||||||||
Mutual funds(d)(e) | 54 | 0 | 0 | 54 | |||||||||||||||
Rabbi trust investments subtotal | 56 | 0 | 0 | 56 | |||||||||||||||
Commodity derivative assets | |||||||||||||||||||
Economic hedges | 493 | 2,582 | 885 | 3,960 | |||||||||||||||
Proprietary trading | 324 | 1,315 | 122 | 1,761 | |||||||||||||||
Effect of netting and allocation of collateral(f) | -863 | -3,131 | -430 | -4,424 | |||||||||||||||
Commodity derivative assets subtotal(g) | -46 | 766 | 577 | 1,297 | |||||||||||||||
Interest rate and foreign currency derivative assets | 30 | 39 | 0 | 69 | |||||||||||||||
Effect of netting and allocation of collateral | -30 | -2 | 0 | -32 | |||||||||||||||
Interest rate and foreign currency derivative assets subtotal | 0 | 37 | 0 | 37 | |||||||||||||||
Other Investments | 0 | 0 | 15 | 15 | |||||||||||||||
Total assets | 4,533 | 5,575 | 1,054 | 11,162 | |||||||||||||||
Liabilities | |||||||||||||||||||
Commodity derivative liabilities | |||||||||||||||||||
Economic hedges | -540 | -1,890 | -590 | -3,020 | |||||||||||||||
Proprietary trading | -328 | -1,256 | -119 | -1,703 | |||||||||||||||
Effect of netting and allocation of collateral(f) | 869 | 3,007 | 404 | 4,280 | |||||||||||||||
Commodity derivative liabilities subtotal | 1 | -139 | -305 | -443 | |||||||||||||||
Interest rate and foreign currency derivative liabilities | -31 | -17 | 0 | -48 | |||||||||||||||
Effect of netting and allocation of collateral | 31 | 1 | 0 | 32 | |||||||||||||||
Interest rate and foreign currency derivative liabilities subtotal | 0 | -16 | 0 | -16 | |||||||||||||||
Deferred compensation obligation | 0 | -114 | 0 | -114 | |||||||||||||||
Total liabilities | 1 | -269 | -305 | -573 | |||||||||||||||
Total net assets | $ | 4,534 | $ | 5,306 | $ | 749 | $ | 10,589 | |||||||||||
(a) Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value. | |||||||||||||||||||
(b) Excludes net assets (liabilities) of $17 million and $(5) million at March 31, 2014 and December 31, 2013, 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 $14 million and $7 million at March 31, 2014 and December 31, 2013, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases. | |||||||||||||||||||
(d) The mutual funds held by the Rabbi trusts include $41 million related to deferred compensation and $1 million related to Supplemental Executive Retirement Plan at March 31, 2014, and $53 million related to deferred compensation and $1 million related to Supplemental Executive Retirement Plan at December 31, 2013. | |||||||||||||||||||
(e) Excludes $33 million and $32 million of the cash surrender value of life insurance investments at March 31, 2014 and December 31, 2013, respectively. | |||||||||||||||||||
(f) Includes collateral postings (received) from counterparties. Collateral posted (received) from counterparties, net of collateral paid to counterparties, totaled $117 million, $332 million and $118 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of March 31, 2014. Collateral posted (received) from counterparties, net of collateral paid to counterparties, totaled $6 million, $(124) million and $(26) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2013. | |||||||||||||||||||
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 months ended March 31, 2014 and 2013: | |||||||||||||||||||
Three Months Ended March 31, 2014 | Nuclear Decommissioning Trust Fund Investments | Pledged Assets for Zion Station Decommissioning | Mark-to-Market Derivatives | Other Investments | Total | ||||||||||||||
Balance as of December 31, 2013 | $ | 350 | $ | 112 | $ | 272 | $ | 15 | $ | 749 | |||||||||
Total realized / unrealized gains (losses) | |||||||||||||||||||
Included in net income | 1 | 0 | -312 | (a) | 0 | -311 | |||||||||||||
Included in regulatory assets | 3 | 0 | 25 | 0 | 28 | ||||||||||||||
Included in payable for Zion Station decommissioning | 0 | -1 | 0 | 0 | -1 | ||||||||||||||
Change in collateral | 0 | 0 | 144 | 0 | 144 | ||||||||||||||
Purchases, sales, issuances and settlements | |||||||||||||||||||
Purchases | 139 | 30 | 10 | 2 | 181 | ||||||||||||||
Sales | -1 | -4 | -2 | 0 | -7 | ||||||||||||||
Settlements | -6 | 0 | 0 | 0 | -6 | ||||||||||||||
Transfers into Level 3 | 0 | 0 | -26 | 0 | -26 | ||||||||||||||
Transfers out of Level 3 | 0 | 0 | 8 | -7 | 1 | ||||||||||||||
Balance as of March 31, 2014 | $ | 486 | $ | 137 | $ | 119 | $ | 10 | $ | 752 | |||||||||
The amount of total losses included in income | |||||||||||||||||||
attributed to the change in unrealized gains (losses) related to assets and liabilities held for the three months ended March 31, 2014 | $ | 0 | $ | 0 | $ | -446 | $ | 0 | $ | -446 | |||||||||
(a) Includes an increase for the reclassification of $134 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three months ended March 31, 2014. | |||||||||||||||||||
Three Months Ended March 31, 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 | 1 | 0 | -127 | (a) | 0 | -126 | |||||||||||||
Included in regulatory assets | 1 | 0 | -8 | (b) | 0 | -7 | |||||||||||||
Change in collateral | 0 | 0 | 33 | 0 | 33 | ||||||||||||||
Purchases, sales, issuances and settlements | |||||||||||||||||||
Purchases | 32 | 22 | -5 | (c) | 0 | 49 | |||||||||||||
Sales | -7 | -7 | -4 | -8 | -26 | ||||||||||||||
Transfers into Level 3 | 0 | 0 | 4 | 0 | 4 | ||||||||||||||
Balance as of March 31, 2013 | $ | 210 | $ | 104 | $ | 260 | $ | 9 | $ | 583 | |||||||||
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 March 31, 2013 | $ | 1 | $ | 0 | $ | -79 | $ | 0 | $ | -78 | |||||||||
(a) Includes the reclassification of $48 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three months ended March 31, 2013. | |||||||||||||||||||
(b) Excludes increases in fair value of $8 million and realized losses reclassified due to settlements of $133 million associated with Generation's financial swap contract with ComEd for the three months ended March 31, 2013. | |||||||||||||||||||
(c) Includes $10 million which Generation was paid to enter into out of the money purchase contracts. | |||||||||||||||||||
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 months ended March 31, 2014 and 2013: | |||||||||||||||||||
Operating Revenues | Purchased Power and Fuel | Other, net (a) | |||||||||||||||||
Total losses included in net income for the three months ended | |||||||||||||||||||
31-Mar-14 | $ | -268 | $ | -44 | $ | 1 | |||||||||||||
Change in the unrealized losses relating to assets and liabilities | |||||||||||||||||||
held for the three months ended March 31, 2014 | $ | -425 | $ | -21 | $ | 0 | |||||||||||||
Operating Revenues | Purchased Power and Fuel | Other, net (a) | |||||||||||||||||
Total gains (losses) included in net income for the three months ended | |||||||||||||||||||
31-Mar-13 | $ | -159 | $ | 32 | $ | 1 | |||||||||||||
Change in the unrealized gains (losses) relating to assets and liabilities | |||||||||||||||||||
held for the three months ended March 31, 2013 | $ | -117 | $ | 38 | $ | 1 | |||||||||||||
(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 March 31, 2014 and December 31, 2013: | |||||||||||||||||||
(a) Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value. | |||||||||||||||||||
(b) Excludes net assets (liabilities) of $17 million and $(5) million at March 31, 2014 and December 31, 2013, 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 $14 million and $7 million at March 31, 2014 and December 31, 2013, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases. | |||||||||||||||||||
(d) Excludes $10 million of the cash surrender value of life insurance investments at both March 31, 2014 and December 31, 2013. | |||||||||||||||||||
(e) Includes collateral postings (received) from counterparties. Collateral posted (received) from counterparties, net of collateral paid to counterparties, totaled $117 million, $332 million and $118 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of March 31, 2014. Collateral posted (received) from counterparties, net of collateral paid to counterparties, totaled $6 million, $(124) million and $(26) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2013. | |||||||||||||||||||
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 months ended March 31, 2014 and 2013: | |||||||||||||||||||
Three Months Ended March 31, 2014 | Nuclear Decommissioning Trust Fund Investments | Pledged Assets for Zion Station Decommissioning | Mark-to-Market Derivatives | Other Investments | Total | ||||||||||||||
Balance as of December 31, 2013 | $ | 350 | $ | 112 | $ | 465 | $ | 15 | $ | 942 | |||||||||
Total realized / unrealized losses | |||||||||||||||||||
Included in net income | 1 | 0 | -312 | (a) | 0 | -311 | |||||||||||||
Included in noncurrent payables to affiliates | 3 | 0 | 0 | 0 | 3 | ||||||||||||||
Included in payable for Zion Station decommissioning | 0 | -1 | 0 | 0 | -1 | ||||||||||||||
Change in collateral | 0 | 0 | 144 | 0 | 144 | ||||||||||||||
Purchases, sales, issuances and settlements | |||||||||||||||||||
Purchases | 139 | 30 | 10 | 2 | 181 | ||||||||||||||
Sales | -1 | -4 | -2 | 0 | -7 | ||||||||||||||
Settlements | -6 | 0 | 0 | 0 | -6 | ||||||||||||||
Transfers into Level 3 | 0 | 0 | -26 | 0 | -26 | ||||||||||||||
Transfers out of Level 3 | 0 | 0 | 8 | -7 | 1 | ||||||||||||||
Balance as of March 31, 2014 | $ | 486 | $ | 137 | $ | 287 | $ | 10 | $ | 920 | |||||||||
The amount of total losses included in income | |||||||||||||||||||
attributed to the change in unrealized gains (losses) related to assets and liabilities held for the three months ended March 31, 2014 | $ | 0 | $ | 0 | $ | -446 | $ | 0 | $ | -446 | |||||||||
(a) Includes an increase for the reclassification of $134 million of realized losses due to the settlement of derivative contracts recorded in results of operations. | |||||||||||||||||||
Three Months Ended March 31, 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 losses | |||||||||||||||||||
Included in net income | 1 | 0 | -144 | (a)(b) | 0 | -143 | |||||||||||||
Included in other comprehensive income | 0 | 0 | -124 | (b) | 0 | -124 | |||||||||||||
Included in noncurrent payables to affiliates | 1 | 0 | 0 | 0 | 1 | ||||||||||||||
Change in collateral | 0 | 0 | 33 | 0 | 33 | ||||||||||||||
Purchases, sales, issuances and settlements | |||||||||||||||||||
Purchases | 32 | 22 | -5 | (c) | 0 | 49 | |||||||||||||
Sales | -7 | -7 | -4 | -8 | -26 | ||||||||||||||
Transfers into Level 3 | 0 | 0 | 4 | 0 | 4 | ||||||||||||||
Balance as of March 31, 2013 | $ | 210 | $ | 104 | $ | 420 | $ | 9 | $ | 743 | |||||||||
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 March 31, 2013 | |||||||||||||||||||
$ | 1 | $ | 0 | $ | -86 | $ | 0 | $ | -85 | ||||||||||
(a) Includes the reclassification of $58 million of realized losses due to the settlement of derivative contracts recorded in results of operations. | |||||||||||||||||||
(b) Includes $8 million of increases in fair value and $133 million of realized losses due to settlements during 2013 of Generation's financial swap contract with ComEd, which eliminates upon consolidation in Exelon's Consolidated Financial Statements. | |||||||||||||||||||
(c) Includes $10 million which Generation was paid to enter into out of the money purchase contracts. | |||||||||||||||||||
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 months ended March 31, 2014 and 2013: | |||||||||||||||||||
Operating Revenues | Purchased Power and Fuel | Other, net(a) | |||||||||||||||||
Total losses included in net income for the three | |||||||||||||||||||
months ended March 31, 2014 | $ | -268 | $ | -44 | $ | 1 | |||||||||||||
Change in the unrealized losses relating to assets and | |||||||||||||||||||
liabilities held for the three months ended March 31, 2014 | $ | -425 | $ | -21 | $ | 0 | |||||||||||||
Operating Revenues | Purchased Power and Fuel | Other, net(a) | |||||||||||||||||
Total gains (losses) included in net income for the three months | |||||||||||||||||||
ended March 31, 2013 | $ | -176 | $ | 32 | $ | 1 | |||||||||||||
Change in the unrealized gains (losses) relating to assets and | |||||||||||||||||||
liabilities held for the three months ended March 31, 2013 | $ | -124 | $ | 38 | $ | 1 | |||||||||||||
(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 March 31, 2014 and December 31, 2013: | |||||||||||||||||||
As of March 31, 2014 | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Assets | |||||||||||||||||||
Rabbi trust investments | |||||||||||||||||||
Mutual funds | $ | 2 | $ | 0 | $ | 0 | $ | 2 | |||||||||||
Rabbi trust investments subtotal | 2 | 0 | 0 | 2 | |||||||||||||||
Total assets | 2 | 0 | 0 | 2 | |||||||||||||||
Liabilities | |||||||||||||||||||
Deferred compensation obligation | 0 | -8 | 0 | -8 | |||||||||||||||
Mark-to-market derivative liabilities(a) | 0 | 0 | -168 | -168 | |||||||||||||||
Total liabilities | 0 | -8 | -168 | -176 | |||||||||||||||
Total net assets (liabilities) | $ | 2 | $ | -8 | $ | -168 | $ | -174 | |||||||||||
As of December 31, 2013 | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Assets | |||||||||||||||||||
Rabbi trust investments | |||||||||||||||||||
Mutual funds | $ | 5 | $ | 0 | $ | 0 | $ | 5 | |||||||||||
Rabbi trust investments subtotal | 5 | 0 | 0 | 5 | |||||||||||||||
Total assets | 5 | 0 | 0 | 5 | |||||||||||||||
Liabilities | |||||||||||||||||||
Deferred compensation obligation | 0 | -8 | 0 | -8 | |||||||||||||||
Mark-to-market derivative liabilities(a) | 0 | 0 | -193 | -193 | |||||||||||||||
Total liabilities | 0 | -8 | -193 | -201 | |||||||||||||||
Total net assets (liabilities) | $ | 5 | $ | -8 | $ | -193 | $ | -196 | |||||||||||
(a) The Level 3 balance includes the current and noncurrent liability of $13 million and $155 million at March 31, 2014, respectively, and $17 million and $176 million at December 31, 2013, respectively, related to floating-to-fixed energy swap contracts with unaffiliated suppliers. | |||||||||||||||||||
The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three months ended March 31, 2014 and 2013: | |||||||||||||||||||
Three Months Ended March 31, 2014 | Mark-to-Market Derivatives | ||||||||||||||||||
Balance as of December 31, 2013 | $ | -193 | |||||||||||||||||
Total realized / unrealized gains included in regulatory assets(a) | 25 | ||||||||||||||||||
Balance as of March 31, 2014 | $ | -168 | |||||||||||||||||
(a) Includes $30 million of decrease in the fair value partially offset by realized gains due to settlements of $5 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended March 31, 2014. | |||||||||||||||||||
Three Months Ended March 31, 2013 | Mark-to-Market Derivatives | ||||||||||||||||||
Balance as of December 31, 2012 | $ | -293 | |||||||||||||||||
Total unrealized / realized gains included in regulatory assets(a)(b) | 133 | ||||||||||||||||||
Balance as of March 31, 2013 | $ | -160 | |||||||||||||||||
Includes $8 million of decreases in fair value and $133 million of realized gains due to settlements associated with ComEd's financial swap with Generation. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements. | |||||||||||||||||||
Includes $11 million of increases in fair value and realized losses due to settlements of $3 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three ended March 31, 2013. | |||||||||||||||||||
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 March 31, 2014 and December 31, 2013: | |||||||||||||||||||
As of March 31, 2014 | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Assets | |||||||||||||||||||
Cash equivalents | $ | 32 | $ | 0 | $ | 0 | $ | 32 | |||||||||||
Rabbi trust investments | |||||||||||||||||||
Mutual funds(a) | 9 | 0 | 0 | 9 | |||||||||||||||
Rabbi trust investments subtotal | 9 | 0 | 0 | 9 | |||||||||||||||
Total assets | 41 | 0 | 0 | 41 | |||||||||||||||
Liabilities | |||||||||||||||||||
Deferred compensation obligation | 0 | -17 | 0 | -17 | |||||||||||||||
Total liabilities | 0 | -17 | 0 | -17 | |||||||||||||||
Total net assets (liabilities) | $ | 41 | $ | -17 | $ | 0 | $ | 24 | |||||||||||
As of December 31, 2013 | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Assets | |||||||||||||||||||
Cash equivalents | $ | 175 | $ | 0 | $ | 0 | $ | 175 | |||||||||||
Rabbi trust investments | |||||||||||||||||||
Mutual funds(a) | 9 | 0 | 0 | 9 | |||||||||||||||
Rabbi trust investments subtotal | 9 | 0 | 0 | 9 | |||||||||||||||
Total assets | 184 | 0 | 0 | 184 | |||||||||||||||
Liabilities | |||||||||||||||||||
Deferred compensation obligation | 0 | -17 | 0 | -17 | |||||||||||||||
Total liabilities | 0 | -17 | 0 | -17 | |||||||||||||||
Total net assets (liabilities) | $ | 184 | $ | -17 | $ | 0 | $ | 167 | |||||||||||
(a) Excludes $14 million of the cash surrender value of life insurance investments at both March 31, 2014 and December 31, 2013. | |||||||||||||||||||
PECO had no Level 3 assets or liabilities measured at fair value on a recurring basis during the three months ended March 31, 2014 and 2013. | |||||||||||||||||||
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 March 31, 2014 and December 31, 2013: | |||||||||||||||||||
As of March 31, 2014 | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Assets | |||||||||||||||||||
Cash equivalents | $ | 30 | $ | 0 | $ | 0 | $ | 30 | |||||||||||
Rabbi trust investments | |||||||||||||||||||
Mutual funds | 4 | 0 | 0 | 4 | |||||||||||||||
Rabbi trust investments subtotal | 4 | 0 | 0 | 4 | |||||||||||||||
Total assets | 34 | 0 | 0 | 34 | |||||||||||||||
Liabilities | |||||||||||||||||||
Deferred compensation obligation | 0 | -4 | 0 | -4 | |||||||||||||||
Total liabilities | 0 | -4 | 0 | -4 | |||||||||||||||
Total net assets (liabilities) | $ | 34 | $ | -4 | $ | 0 | $ | 30 | |||||||||||
As of December 31, 2013 | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Assets | |||||||||||||||||||
Cash equivalents | $ | 31 | $ | 0 | $ | 0 | $ | 31 | |||||||||||
Rabbi trust investments | |||||||||||||||||||
Mutual funds | 6 | 0 | 0 | 6 | |||||||||||||||
Rabbi trust investments subtotal | 6 | 0 | 0 | 6 | |||||||||||||||
Total assets | 37 | 0 | 0 | 37 | |||||||||||||||
Liabilities | |||||||||||||||||||
Deferred compensation obligation | 0 | -6 | 0 | -6 | |||||||||||||||
Total liabilities | 0 | -6 | 0 | -6 | |||||||||||||||
Total net assets (liabilities) | $ | 37 | $ | -6 | $ | 0 | $ | 31 | |||||||||||
BGE had no Level 3 assets or liabilities measured at fair value on a recurring basis during the three months ended March 31, 2014 and 2013. | |||||||||||||||||||
Valuation Techniques Used to Determine Fair Value | |||||||||||||||||||
The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above. | |||||||||||||||||||
Cash Equivalents (Exelon, Generation, ComEd, PECO and BGE). The Registrants' cash equivalents include investments with maturities of three months or less when purchased. The cash equivalents shown in the fair value tables are comprised of investments in mutual and money market funds. The fair values of the shares of these funds are based on observable market prices and, therefore, have been categorized in Level 1 in the fair value hierarchy. | |||||||||||||||||||
Nuclear Decommissioning Trust Fund Investments and Pledged Assets for Zion Station Decommissioning (Exelon and Generation). The trust fund investments have been established to satisfy Generation's nuclear decommissioning obligations as required by the NRC. The NDT funds hold debt and equity securities directly and indirectly through commingled funds. Generation's investment policies place limitations on the types and investment grade ratings of the securities that may be held by the trusts. These policies limit the trust funds' exposures to investments in highly illiquid markets and other alternative investments. Investments with maturities of three months or less when purchased, including certain short-term fixed income securities are considered cash equivalents and included in the recurring fair value measurements hierarchy as Level 1 or Level 2. | |||||||||||||||||||
With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are obtained from direct feeds from market exchanges, which Generation is able to independently corroborate. The fair values of equity securities held directly by the trust funds are based on quoted prices in active markets and are categorized in Level 1. Equity securities held individually are primarily traded on the New York Stock Exchange and NASDAQ-Global Select Market, which contain only actively traded securities due to the volume trading requirements imposed by these exchanges. | |||||||||||||||||||
For fixed income securities, multiple prices from pricing services are obtained whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class or issue for each security. The trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another price source is considered to be preferable. Generation has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Generation selectively corroborates the fair values of securities by comparison to other market-based price sources. U.S. Treasury securities are categorized as Level 1 because they trade in a highly liquid and transparent market. The fair values of fixed income securities, excluding U.S. Treasury securities, are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities, adjusted for observable differences and are categorized in Level 2. The fair values of private placement fixed income securities are determined using a third party valuation that contains significant unobservable inputs and are categorized in Level 3. | |||||||||||||||||||
Equity and fixed income commingled funds and fixed income mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives. The fair values of fixed income commingled and mutual funds held within the trust funds, which generally hold short-term fixed income securities and are not subject to restrictions regarding the purchase or sale of shares, are derived from observable prices. The objectives of the remaining equity commingled funds in which Exelon and Generation invest primarily seek to track the performance of certain equity indices by purchasing equity securities to replicate the capitalization and characteristics of the indices. Comingled 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 10 — Nuclear Decommissioning for further discussion on the NDT fund investments. | |||||||||||||||||||
Middle market lending are investments in loans or managed funds which invest in private companies. Generation elected the fair value option for its investments in certain limited partnerships that invest in middle market lending managed funds. The fair value of these loans is determined using a combination of valuation models including cost models, market models, and income models. Investments in middle market lending are categorized as Level 3 because the fair value of these securities is based largely on inputs that are unobservable and utilize complex valuation models. Investments in middle market lending typically cannot be redeemed until maturity of the term loan. | |||||||||||||||||||
As of March 31, 2014, Generation has outstanding commitments to invest in middle market lending, corporate debt securities, private equity investments, and real estate investments of approximately $469 million. These commitments will be funded by Generation's existing nuclear decommissioning trust funds. | |||||||||||||||||||
Rabbi Trust Investments (Exelon, Generation, ComEd, PECO and BGE). The Rabbi trusts were established to hold assets related to deferred compensation plans existing for certain active and retired members of Exelon's executive management and directors. The investments in the Rabbi trusts are included in investments in the Registrants' Consolidated Balance Sheets and consist primarily of mutual funds. These funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives, which are consistent with Exelon's overall investment strategy. Mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability of the prices. | |||||||||||||||||||
Mark-to-Market Derivatives (Exelon, Generation, and ComEd). Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy. Certain derivatives' pricing is verified using indicative price quotations available through brokers or over-the-counter, on-line exchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask, mid-point prices and are obtained from sources that the Registrants believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. This includes consideration of actual transaction volumes, market delivery points, bid-ask spreads and contract duration. The remainder of derivative contracts are valued using the Black model, an industry standard option valuation model. The Black model takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the future prices of energy, interest rates, volatility, credit worthiness and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps and options, model inputs are generally observable. Such instruments are categorized in Level 2. The Registrants' derivatives are predominately at liquid trading points. For derivatives that trade in less liquid markets with limited pricing information model inputs generally would include both observable and unobservable inputs. These valuations may include an estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. Such instruments are categorized in Level 3. | |||||||||||||||||||
Exelon may utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to achieve its targeted level of variable-rate debt as a percent of total debt. In addition, the Registrants may utilize interest rate derivatives to lock in interest rate levels in anticipation of future financings. These interest rate derivatives are typically designated as cash flow hedges. Exelon determines the current fair value by calculating the net present value of expected payments and receipts under the swap agreement, based on and discounted by the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk and other market parameters. As these inputs are based on observable data and valuations of similar instruments, the interest rate swaps are categorized in Level 2 in the fair value hierarchy. See Note 7 — Derivative Financial Instruments for further discussion on mark-to-market derivatives. | |||||||||||||||||||
Deferred Compensation Obligations (Exelon, Generation, ComEd, PECO and BGE). The Registrants' deferred compensation plans allow participants to defer certain cash compensation into a notional investment account. The Registrants include such plans in other current and noncurrent liabilities in their Consolidated Balance Sheets. The value of the Registrants' deferred compensation obligations is based on the market value of the participants' notional investment accounts. The notional investments are comprised primarily of mutual funds, which are based on observable market prices. However, since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized as Level 2 in the fair value hierarchy. | |||||||||||||||||||
Additional Information Regarding Level 3 Fair Value Measurements (Exelon, Generation, ComEd) | |||||||||||||||||||
Mark-to-Market Derivatives (Exelon, Generation, ComEd). For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract tenure extends into unobservable periods. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 as the model inputs generally are not observable. Exelon's RMC approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The RMC is chaired by the chief risk officer and includes the chief financial officer, corporate controller, general counsel, treasurer, vice president of strategy, vice president of audit services and officers representing Exelon's business units. The RMC reports to the Exelon Board of Directors on the scope of the risk management activities and is responsible for approving all valuation procedures at Exelon. Forward price curves for the power market utilized by the front office to manage the portfolio, are reviewed and verified by the middle office, and used for financial reporting by the back office. The Registrants consider credit and nonperformance risk in the valuation of derivative contracts categorized in Level 2 and 3, including both historical and current market data in its assessment of credit and nonperformance risk by counterparty. Due to master netting agreements and collateral posting requirements, the impacts of credit and nonperformance risk were not material to the financial statements. | |||||||||||||||||||
Disclosed below is detail surrounding the Registrants' significant Level 3 valuations. The calculated fair value includes marketability discounts for margining provisions and other attributes. Generation's Level 3 balance generally consists of forward sales and purchases of power and natural gas, coal purchases, certain transmission congestion contracts, and project financing debt. Generation utilizes various inputs and factors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors include forward commodity prices, commodity price volatility, contractual volumes, delivery location, interest rates, credit quality of counterparties and credit enhancements. | |||||||||||||||||||
For commodity derivatives, the primary input to the valuation models is the forward commodity price curve for each instrument. Forward commodity price curves are derived by risk management for liquid locations and by the traders and portfolio managers for illiquid locations. All locations are reviewed and verified by risk management considering published exchange transaction prices, executed bilateral transactions, broker quotes, and other observable or public data sources. The relevant forward commodity curve used to value each of the derivatives depends on a number of factors, including commodity type, delivery location, and delivery period. Price volatility varies by commodity and location. When appropriate, Generation discounts future cash flows using risk free interest rates with adjustments to reflect the credit quality of each counterparty for assets and Generation's own credit quality for liabilities. The level of observability of a forward commodity price is generally due to the delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are more liquid and prices are observable for up to three years in the future. The observability period of volatility is generally shorter than the underlying power curve used in option valuations. The forward curve for a less liquid location is estimated by using the forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not typically represent a majority of the instrument's market price. As a result, the change in fair value is closely tied to liquid market movements and not a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across all Level 3 power and gas delivery locations is approximately $3.83 and $0.37 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 7 – 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 March 31, 2014 (c) | Valuation Technique | Unobservable Input | Range | |||||||||||||||
Mark-to-market derivatives – Economic Hedges (Generation) (a) | $ | 186 | Discounted Cash Flow | Forward power price | $ | 19 | - | $ | 155 | (d) | |||||||||
Forward gas price | $ | 2.18 | - | $ | 17.65 | (d) | |||||||||||||
Option Model | Volatility percentage | 14 | % | - | 207 | % | |||||||||||||
Mark-to-market derivatives – Proprietary trading (Generation) (a) | $ | -17 | Discounted Cash Flow | Forward power price | $ | 26 | - | $ | 152 | (d) | |||||||||
Option Model | Volatility percentage | 12 | % | - | 59 | % | |||||||||||||
Mark-to-market derivatives (ComEd) | $ | -168 | Discounted Cash Flow | Forward heat rate (b) | 8 | x | - | 9 | x | ||||||||||
Marketability reserve | 3.5 | % | - | 8 | % | ||||||||||||||
Renewable factor | 87 | % | - | 127 | % | ||||||||||||||
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 $118 million as of March 31, 2014. | |||||||||||||||||||
The upper ends of the ranges are driven by the winter power and gas prices in the New England region. Without the New England region, the upper ends of the ranges for power and gas would be approximately $114 and $10.62, respectively. | |||||||||||||||||||
Type of trade | Fair Value at December 31, 2013 (c) | Valuation Technique | Unobservable Input | Range | |||||||||||||||
Mark-to-market derivatives – Economic Hedges (Generation) (a) | $ | 488 | Discounted Cash Flow | Forward power price | $ | 8 | - | $ | 176 | (d) | |||||||||
Forward gas price | $ | 2.98 | - | $ | 16.63 | (d) | |||||||||||||
Option Model | Volatility percentage | 15 | % | - | 142 | % | |||||||||||||
Mark-to-market derivatives – Proprietary trading (Generation) (a) | $ | 3 | Discounted Cash Flow | Forward power price | $ | 10 | - | $ | 176 | (d) | |||||||||
Option Model | Volatility percentage | 14 | % | - | 19 | % | |||||||||||||
Mark-to-market derivatives (ComEd) | $ | -193 | Discounted Cash Flow | Forward heat rate (b) | 8 | x | - | 9 | x | ||||||||||
Marketability reserve | 3.5 | % | - | 8 | % | ||||||||||||||
Renewable factor | 84 | % | - | 128 | % | ||||||||||||||
The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions. | |||||||||||||||||||
Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract's delivery. | |||||||||||||||||||
The fair values do not include cash collateral held on level three positions of $26 million as of December 31, 2013 | |||||||||||||||||||
The upper ends of the ranges are driven by the winter power and gas prices in the New England region. Without the New England region, the upper ends of the ranges for power and gas would be approximately $100 and $5.70, respectively. | |||||||||||||||||||
The inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted. The significant unobservable inputs used in the fair value measurement of Generation's commodity derivatives are forward commodity prices and for options is price volatility. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give Generation the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give Generation the obligation or right to sell a commodity). Increases (decreases) in volatility would increase (decrease) the value for the holder of the option (writer of the option). Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the reserves listed above would decrease the fair value of the positions. An increase to the heat rate or renewable factors would increase the fair value accordingly. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets. | |||||||||||||||||||
Nuclear Decommissioning Trust Fund Investments and Pledged Assets for Zion Station Decommissioning (Exelon and Generation). For middle market lending, certain corporate debt securities, and private equity investments the fair value is determined using a combination of valuation models including cost models, market models and income models. The valuation estimates are based on valuations of comparable companies, discounting the forecasted cash flows of the portfolio company, estimating the liquidation or collateral value of the portfolio company or its assets, considering offers from third parties to buy the portfolio company, its historical and projected financial results, as well as other factors that may impact value. Significant judgment is required in the application of discounts or premiums applied to the prices of comparable companies for factors such as size, marketability, credit risk and relative performance. | |||||||||||||||||||
Because Generation relies on third-party fund managers to develop the quantitative unobservable inputs without adjustment for the valuations of its' Level 3 investments, quantitative information about significant unobservable inputs used in valuing these investments is not reasonably available to Generation. This includes information regarding the sensitivity of the fair values to changes in the unobservable inputs. Generation gains an understanding of the fund managers' inputs and assumptions used in preparing the valuations. Generation performed procedures to assess the reasonableness of the valuations. For a sample of its' Level 3 investments, Generation reviewed independent valuations and reviewed the assumptions in the detailed pricing models used by the fund managers. | |||||||||||||||||||
Derivative_Financial_Instrumen
Derivative Financial Instruments (Exelon, Generation, ComEd, PECO and BGE) | 3 Months Ended | ||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||
Derivative Financial Instruments [Line Items] | ' | ||||||||||||||||
Derivative Financial Instruments (Exelon, Generation, ComEd, PECO and BGE) | ' | ||||||||||||||||
7. Derivative Financial Instruments (Exelon, Generation, ComEd, PECO and BGE) | |||||||||||||||||
The Registrants use derivative instruments to manage commodity price risk and interest rate risk related to ongoing business operations. | |||||||||||||||||
Commodity Price Risk (Exelon, Generation, ComEd, PECO and BGE) | |||||||||||||||||
To the extent the amount of energy Exelon generates differs from the amount of energy it has contracted to sell, the Registrants are exposed to market fluctuations in the prices of electricity, fossil fuels and other commodities. The Registrants employ established policies and procedures to manage their risks associated with market fluctuations by entering into physical and financial derivative contracts, including swaps, futures, forwards, options and short-term and long-term commitments to purchase and sell energy and energy-related products. The Registrants believe these instruments, which are classified as either economic hedges or non-derivatives, mitigate exposure to fluctuations in commodity prices. | |||||||||||||||||
Derivative accounting guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings each period. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include normal purchase normal sale (NPNS), cash flow hedge, and fair value hedge. For commodity transactions, effective with the date of merger with Constellation, Generation no longer utilizes the special election provided for by the cash flow hedge designation and de-designated all of its existing cash flow hedges prior to the merger. Because the underlying forecasted transactions remain at least reasonably possible, the fair value of the effective portion of these cash flow hedges was frozen in accumulated OCI and reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurs, or becomes probable of not occurring. None of Constellation's designated cash flow hedges for commodity transactions prior to the merger were re-designated as cash flow hedges. The effect of this decision is that all derivative economic hedges for commodities are recorded at fair value through earnings for the combined company, referred to as economic hedges in the following tables. The Registrants have applied the NPNS scope exception to certain derivative contracts for the forward sale of generation, power procurement agreements, and natural gas supply agreements. Non-derivative contracts for access to additional generation and certain sales to load-serving entities are accounted for primarily under the accrual method of accounting, which is further discussed in Note 22 – Commitments and Contingencies of the Exelon 2013 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. As such, Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities; including power and gas sales, fuel and energy purchases, natural gas transportation and pipeline capacity agreements and other energy-related products marketed and purchased. In order to manage these risks, Generation may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from forecasted sales of energy and gas 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 March 31, 2014, the percentage of expected generation hedged for the major reportable segments was 91%-94%, 64%-67%, and 37%-40% for 2014, 2015, and 2016, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted capacity. Equivalent sales represent all hedging products, which include economic hedges and certain non-derivative contracts including, Generation's sales to ComEd, PECO and BGE to serve their retail load. | |||||||||||||||||
On December 17, 2010, ComEd entered into several 20-year floating-to-fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. Delivery under the contracts began in June 2012. Pursuant to the ICC's Order on December 19, 2012, ComEd's commitments under the existing long-term contracts for energy and associated RECs were reduced for the June 2013 through May 2014 procurement period. In addition, the ICC's December 18, 2013 Order approved the reduction of ComEd's commitments under those contracts for the June 2014 through May 2015 procurement period, and the amount of the reduction was approved in March 2014. These contracts are designed to lock in a portion of the long-term commodity price risk resulting from the renewable energy resource procurement requirements in the Illinois Settlement Legislation. ComEd has not elected hedge accounting for these derivative financial instruments. ComEd records the fair value of the swap contracts on its balance sheet. Because ComEd receives full cost recovery for energy procurement and related costs from retail customers, the change in fair value each period is recorded by ComEd as a regulatory asset or liability. See Note 3 – Regulatory Matters of the Exelon 2013 Form 10-K 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 4 - Regulatory Matters. Based on Pennsylvania legislation and the DSP Programs permitting PECO to recover its electric supply procurement costs from retail customers with no mark-up, PECO's price risk related to electric supply procurement is limited. PECO locked in fixed prices for a significant portion of its commodity price risk through full requirements contracts and block contracts. PECO has certain full requirements contracts and block contracts that are considered derivatives and qualify for the NPNS scope exception under current derivative authoritative guidance. | |||||||||||||||||
PECO's natural gas procurement policy is designed to achieve a reasonable balance of long-term and short-term gas purchases under different pricing approaches in order to achieve system supply reliability at the least cost. PECO's reliability strategy is two-fold. First, PECO must assure that there is sufficient transportation capacity to satisfy delivery requirements. Second, PECO must ensure that a firm source of supply exists to utilize the capacity resources. All of PECO's natural gas supply and asset management agreements that are derivatives either qualify for the NPNS scope exception and have been designated as such, or have no mark-to-market balances because the derivatives are index priced. Additionally, in accordance with the 2013 PAPUC PGC settlement and to reduce the exposure of PECO and its customers to natural gas price volatility, PECO has continued its program to purchase natural gas for both winter and summer supplies using a layered approach of locking-in prices ahead of each season with long-term gas purchase agreements (those with primary terms of at least twelve months). Under the terms of the 2013 PGC settlement, PECO is required to lock in (i.e., economically hedge) the price of a minimum volume of its long-term gas commodity purchases. PECO's gas-hedging program is designed to cover about 30% of planned natural gas purchases in support of projected firm sales. The hedging program for natural gas procurement has no direct impact on PECO's financial position or results of operations as natural gas costs are fully recovered from customers under the PGC. | |||||||||||||||||
BGE has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC. The SOS rates charged recover BGE's wholesale power supply costs and include an administrative fee. The administrative fee includes an incremental cost component and a shareholder return component for commercial and industrial rate classes. BGE's price risk related to electric supply procurement is limited. BGE locks in fixed prices for all of its SOS requirements through full requirements contracts. Certain of BGE's full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other BGE full requirements contracts are not derivatives. | |||||||||||||||||
BGE provides natural gas to its customers under a MBR mechanism approved by the MDPSC. Under this mechanism, BGE's actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between BGE's actual cost and the market index is shared equally between shareholders and customers. BGE must also secure fixed price contracts for at least 10%, but not more than 20%, of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period. These fixed-price contracts are not subject to sharing under the MBR mechanism. BGE also ensures it has sufficient pipeline transportation capacity to meet customer requirements. All of BGE's natural gas supply and asset management agreements qualify for the NPNS scope exception and result in physical delivery. | |||||||||||||||||
Proprietary Trading. Generation also enters into certain energy-related derivatives for proprietary trading purposes. Proprietary trading includes all contracts entered into with the intent of benefiting from shifts or changes in market prices as opposed to those entered into with the intent of hedging or managing risk. Proprietary trading activities are subject to limits established by Exelon's RMC. The proprietary trading activities, which included settled physical sales volumes of 2,494 GWhs and 1,572 GWhs for the three months ended March 31, 2014 and 2013, 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 March 31, 2014, Exelon and Generation had $1,550 million and $700 million of notional amounts of fixed-to-floating hedges outstanding, respectively, and $530 million and $430 million of notional amounts of floating-to-fixed hedges outstanding, respectively. Assuming the fair value and cash flow interest rate hedges are 100% effective, a hypothetical 50 bps increase in the interest rates associated with unhedged variable-rate debt (excluding Commercial Paper) and fixed-to-floating swaps would result in approximately a $2 million decrease in Exelon Consolidated pre-tax income for the three months ended March 31, 2014. To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are typically designated as economic hedges. Below is a summary of the interest rate and foreign currency hedges as of March 31, 2014. | |||||||||||||||||
Generation | Other | Exelon | |||||||||||||||
Description | Derivatives Designated as Hedging Instruments | Economic Hedges | Proprietary Trading (a) | Collateral and Netting (b) | Subtotal | Derivatives Designated as Hedging Instruments | Total | ||||||||||
Mark-to-market derivative assets | |||||||||||||||||
(current assets) | $ | 0 | $ | 4 | $ | 12 | $ | -14 | $ | 2 | $ | 0 | $ | 2 | |||
Mark-to-market derivative assets | |||||||||||||||||
(noncurrent assets) | 20 | 2 | 13 | -8 | 27 | 10 | 37 | ||||||||||
Total mark-to-market derivative assets | $ | 20 | $ | 6 | $ | 25 | $ | -22 | $ | 29 | $ | 10 | $ | 39 | |||
Mark-to-market derivative liabilities | |||||||||||||||||
(current liabilities) | $ | -1 | $ | -3 | $ | -15 | $ | 17 | $ | -2 | $ | 0 | $ | -2 | |||
Mark-to-market derivative liabilities | |||||||||||||||||
(noncurrent liabilities) | -15 | -1 | -10 | 11 | -15 | -1 | -16 | ||||||||||
Total mark-to-market derivative liabilities | $ | -16 | $ | -4 | $ | -25 | $ | 28 | $ | -17 | $ | -1 | $ | -18 | |||
Total mark-to-market derivative | |||||||||||||||||
net assets (liabilities) | $ | 4 | $ | 2 | $ | 0 | $ | 6 | $ | 12 | $ | 9 | $ | 21 | |||
Generation enters into interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The characterization of the interest rate derivative contracts between the proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rate exposure. Generation does not utilize proprietary trading interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates. | |||||||||||||||||
Represents the netting of fair value balances with the same counterparty and any associated cash collateral. | |||||||||||||||||
The following table provides a summary of the interest rate hedge balances recorded by the Registrants as of December 31, 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) | $ | 0 | $ | 3 | $ | 15 | $ | -19 | $ | -1 | $ | 0 | $ | -1 | |||
Mark-to-market derivative assets | |||||||||||||||||
(noncurrent assets) | 26 | 3 | 15 | -13 | 31 | 7 | 38 | ||||||||||
Total mark-to-market derivative assets | $ | 26 | $ | 6 | $ | 30 | $ | -32 | $ | 30 | $ | 7 | $ | 37 | |||
Mark-to-market derivative liabilities | |||||||||||||||||
(current liabilities) | $ | -1 | $ | -1 | $ | -18 | $ | 19 | $ | -1 | $ | 0 | $ | -1 | |||
Mark-to-market derivative liabilities | |||||||||||||||||
(noncurrent liabilities) | -10 | -1 | -13 | 13 | -11 | -4 | -15 | ||||||||||
Total mark-to-market derivative liabilities | $ | -11 | $ | -2 | $ | -31 | $ | 32 | $ | -12 | $ | -4 | $ | -16 | |||
Total mark-to-market derivative | |||||||||||||||||
net assets (liabilities) | $ | 15 | $ | 4 | $ | -1 | $ | 0 | $ | 18 | $ | 3 | $ | 21 | |||
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 proprietary trading interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates. | |||||||||||||||||
Represents the netting of fair value balances with the same counterparty and any associated cash collateral. | |||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
Income Statement | 2014 | 2013 | 2014 | 2013 | |||||||||||||
Location | Gain (Loss) on Swaps | Gain (Loss) on Borrowings | |||||||||||||||
Generation | Interest expense(a) | $ | -5 | $ | -4 | $ | -1 | $ | -1 | ||||||||
Exelon | Interest expense | $ | 2 | $ | -6 | $ | 4 | $ | 1 | ||||||||
__________ | |||||||||||||||||
For the three months ended March 31, 2014 and 2013, the loss on Generation swaps included $4 million and $4 million realized in earnings, respectively, with an immaterial amount excluded from hedge effectiveness testing. | |||||||||||||||||
During the first quarter of 2014, Exelon entered into $50 million and $75 million of notional amounts of fixed-to-floating fair value hedges related to interest rate swaps, which expire in 2019 and 2020, respectively. At March 31, 2014, Exelon and Generation had total outstanding fixed-to-floating fair value hedges related to interest rate swaps of $1,400 million and $550 million, with unrealized gains of $28 million and $19 million, respectively. At December 31, 2013, Exelon and Generation had outstanding fixed-to-floating fair value hedges related to interest rate swaps of $1,275 million and $550 million, with unrealized gains of $26 million and $23 million, respectively. During the three months ended March 31, 2014 and 2013, the impact on the results of operations as a result of ineffectiveness from fair value hedges was a $5 million gain and immaterial, respectively. | |||||||||||||||||
Cash Flow Hedges. In connection with the DOE guaranteed loan for the Antelope Valley project financings, as discussed in Note 8 – Debt and Credit Agreements, Generation entered into a floating-to-fixed forward starting interest rate swap with a notional amount of $485 million and a mandatory early termination date of September 30, 2014. The swap hedges approximately 75% of Generation's future interest rate exposure associated with the financing and was designated as a cash flow hedge. As such, the effective portion of the hedge is recorded in other comprehensive income within Generation's Consolidated Balance Sheets, with any ineffectiveness recorded in Generation's Consolidated Statements of Operations and Comprehensive Income. Net gains (or losses) from settlement of the hedges, to the extent effective, are amortized as an adjustment to the interest expense over the term of the DOE guaranteed loan. | |||||||||||||||||
Every time Generation draws down on the loan, an offsetting hedge (fixed-to-floating) is executed and a portion of the cash flow hedge with a notional amount equal to the offsetting hedge, is de-designated and the related gains or losses going forward are reflected in earnings, which are largely offset by the losses or gains in the offsetting hedge. | |||||||||||||||||
Antelope Valley received its first loan advance on April 5, 2012, and a series of additional advances subsequently. Generation has entered into a series of fixed-to-floating interest rate swaps with an aggregated notional amount of $350 million, approximately 75% of the loan advance amount to offset portions of the original interest rate hedge, which are not designated as cash flow hedges. The remaining cash flow hedge has a notional amount of $135 million. At March 31, 2014, Generation's mark-to-market derivative liability relating to the interest rate swaps in connection with the loan agreement to fund Antelope Valley was $14 million. | |||||||||||||||||
During the third quarter of 2011, a subsidiary of Constellation entered into floating-to-fixed interest rate swaps to manage a portion of the interest rate exposure for anticipated long-term borrowings to finance Sacramento PV Energy. The swaps have a total notional amount of $28 million as of March 31, 2014 and expire in 2027. After the closing of the merger with Constellation, the swaps were re-designated as cash flow hedges. At March 31, 2014, the subsidiary had a $2 million derivative liability related to these swaps. | |||||||||||||||||
During the third quarter of 2012, a subsidiary of Exelon Generation entered into a floating-to-fixed interest rate swap to manage a portion of the interest rate exposure of anticipated long-term borrowings to finance Constellation Solar Horizons. The swap has a notional amount of $27 million as of March 31, 2014 and expires in 2030. This swap is designated as a cash flow hedge. At March 31, 2014, the subsidiary had a $2 million derivative asset related to the swap. | |||||||||||||||||
During the first quarter of 2014, a subsidiary of Exelon Generation entered into floating-to-fixed interest rate swaps to manage a portion of the interest rate exposure with long-term borrowings to finance ExGen Renewables I, LLC. See Note 8 – Debt and Credit Agreements for additional information regarding the financing. The swaps have a notional amount of $240 million as of March 31, 2014 and expire in 2020. The swaps are designated as cash flow hedges. At March 31, 2014, the subsidiary had an immaterial derivative liability related to the swaps. | |||||||||||||||||
During the first quarter of 2014, Exelon entered into $100 million of floating-to-fixed interest rate hedges to manage interest rate risks associated with anticipated future debt issuance. The swaps are designated as cash flow hedges. At March 31, 2014, Exelon had an immaterial derivative asset related to the swaps. | |||||||||||||||||
During the three months ended March 31, 2014 and 2013, the impact on the results of operations as a result of ineffectiveness from cash flow hedges was immaterial. | |||||||||||||||||
Economic Hedges. At March 31, 2014, Generation had $195 million in notional amounts of interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions and $164 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 March 31, 2014, Exelon and Generation had $150 million in notional amounts of fixed-to-floating interest rate swaps that are marked-to-market, with unrealized gains of $2 million. These swaps, which were acquired as part of the merger with Constellation, expire in 2014. During the three months ended March 31, 2014 and 2013, 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 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 March 31, 2014 and December 31, 2013, $8 million of cash collateral held and $10 million of cash collateral posted, respectively, was not offset against derivative positions because such collateral was not associated with any energy-related derivatives 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 March 31, 2014: | |||||||||||||||||
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) | $ | 3,401 | $ | 1,146 | $ | -3,793 | $ | 754 | $ | 0 | $ | 754 | |||||
Mark-to-market derivative assets | |||||||||||||||||
(noncurrent assets) | 1,240 | 195 | -901 | 534 | 0 | 534 | |||||||||||
Total mark-to-market derivative | |||||||||||||||||
assets | $ | 4,641 | $ | 1,341 | $ | -4,694 | $ | 1,288 | $ | 0 | $ | 1,288 | |||||
Mark-to-market derivative liabilities | |||||||||||||||||
(current liabilities) | $ | -3,348 | $ | -1,112 | $ | 4,224 | $ | -236 | $ | -13 | $ | -249 | |||||
Mark-to-market derivative liabilities | |||||||||||||||||
(noncurrent liabilities) | -947 | -206 | 1,037 | -116 | -155 | -271 | |||||||||||
Total mark-to-market derivative | |||||||||||||||||
liabilities | $ | -4,295 | $ | -1,318 | $ | 5,261 | $ | -352 | $ | -168 | $ | -520 | |||||
Total mark-to-market derivative | |||||||||||||||||
net assets (liabilities) | $ | 346 | $ | 23 | $ | 567 | $ | 936 | $ | -168 | $ | 768 | |||||
__________ | |||||||||||||||||
(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 $(179) million and $(36) million, respectively, and current and noncurrent liabilities are shown net of collateral of $(252) million and $(100) million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $567 million at March 31, 2014. | |||||||||||||||||
(c) Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers. | |||||||||||||||||
The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2013: | |||||||||||||||||
Generation | ComEd | Exelon | |||||||||||||||
Economic | Proprietary | Collateral and | Economic | Total | |||||||||||||
Description | Hedges | Trading | Netting(a) | Subtotal(b) | Hedges (c) | Derivatives | |||||||||||
Mark-to-market derivative assets | |||||||||||||||||
(current assets) | $ | 2,616 | $ | 1,476 | $ | -3,364 | $ | 728 | $ | 0 | $ | 728 | |||||
Mark-to-market derivative assets | |||||||||||||||||
(noncurrent assets) | 1,344 | 285 | -1,060 | 569 | 0 | 569 | |||||||||||
Total mark-to-market derivative | |||||||||||||||||
assets | $ | 3,960 | $ | 1,761 | $ | -4,424 | $ | 1,297 | $ | 0 | $ | 1,297 | |||||
Mark-to-market derivative liabilities | |||||||||||||||||
(current liabilities) | $ | -2,023 | $ | -1,410 | $ | 3,292 | $ | -141 | $ | -17 | $ | -158 | |||||
Mark-to-market derivative liabilities | |||||||||||||||||
(noncurrent liabilities) | -804 | -293 | 988 | -109 | -176 | -285 | |||||||||||
Total mark-to-market derivative | |||||||||||||||||
liabilities | $ | -2,827 | $ | -1,703 | $ | 4,280 | $ | -250 | $ | -193 | $ | -443 | |||||
Total mark-to-market derivative | |||||||||||||||||
net assets (liabilities) | $ | 1,133 | $ | 58 | $ | -144 | $ | 1,047 | $ | -193 | $ | 854 | |||||
__________ | |||||||||||||||||
(a) Exelon and Generation net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, and letters of credit. These are not reflected in the table above. | |||||||||||||||||
(b) Current and noncurrent assets are shown net of collateral of $84 million and $72 million, respectively, and current and noncurrent liabilities are shown net of collateral of $(12) million and $0 million, respectively. The total cash collateral received, net of cash collateral posted and offset against mark-to-market assets and liabilities was $144 million at December 31, 2013. | |||||||||||||||||
(c) Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers. | |||||||||||||||||
Cash Flow Hedges (Exelon and Generation). 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 $156 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 2014. | |||||||||||||||||
The tables below provide the activity of accumulated OCI related to cash flow hedges for the three months ended March 31, 2014 and 2013, containing information about the changes in the fair value of cash flow hedges and the reclassification from accumulated OCI into results of operations. The amounts reclassified from accumulated OCI, when combined with the impacts of the actual physical power sales, result in the ultimate recognition of net revenues at the contracted price. | |||||||||||||||||
Total Cash Flow Hedge OCI Activity, Net of Income Tax | |||||||||||||||||
Generation | Exelon | ||||||||||||||||
Three Months Ended March 31, 2014 | Income Statement Location | Energy-Related Hedges | Total Cash Flow Hedges | ||||||||||||||
Accumulated OCI derivative gain at December 31, 2013 | $ | 119 | (a) | $ | 120 | ||||||||||||
Effective portion of changes in fair value | 0 | -1 | |||||||||||||||
Reclassifications from accumulated OCI to net income | Operating Revenues | -24 | -24 | ||||||||||||||
Accumulated OCI derivative gain at March 31, 2014 | $ | 95 | (a) | $ | 95 | ||||||||||||
(a) Excludes $3 million and $15 million of gains, net of taxes, related to interest rate swaps and treasury rate locks as of March 31, 2014 and December 31, 2013. | |||||||||||||||||
Total Cash Flow Hedge OCI Activity, Net of Income Tax | |||||||||||||||||
Generation | Exelon | ||||||||||||||||
Three Months Ended March 31, 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 | -1 | (d) | ||||||||||||||
Reclassifications from accumulated OCI to net income | Operating Revenues | -135 | (b) | -58 | |||||||||||||
Accumulated OCI derivative gain at March 31, 2013 | $ | 397 | (a)(c) | $ | 309 | ||||||||||||
. | |||||||||||||||||
(a) Includes $58 million and $133 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, as of March 31, 2013 and December 31, 2012, respectively. | |||||||||||||||||
(b) Includes a $75 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 $16 million of losses and $20 million of losses, net of taxes, related to interest rate swaps and treasury rate locks as of March 31, 2013 and December 31, 2012, respectively. | |||||||||||||||||
(d) Includes $3 million of losses, net of taxes, related to the effective portion of changes in fair value of interest rate swaps and treasury rate locks | |||||||||||||||||
During the three months ended March 31, 2014 and 2013, 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 $39 million pre-tax gain and $223 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. | |||||||||||||||||
The effect of Exelon's former energy-related cash flow hedge activity on pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $39 million pre-tax gain for the three months ended March 31, 2014, and a $99 million pre-tax gain for the three months ended March 31, 2013. Neither Exelon nor Generation will incur changes in cash flow hedge ineffectiveness in future periods as all energy-related cash flow hedge positions were de-designated prior to the merger date. | |||||||||||||||||
Economic Hedges (Exelon and Generation). These instruments represent hedges that economically mitigate exposure to fluctuations in commodity prices and include financial options, futures, swaps, physical forward sales and purchases, but for which the fair value or cash flow hedge elections were not made. Additionally, Generation enters into interest rate derivative contracts and foreign exchange currency swaps to manage the exposure related to the interest rate component of commodity positions and international purchases of commodities in currencies other than U.S. Dollars. For the three months ended March 31, 2014 and 2013, 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 March 31, 2014 | Revenues | and Fuel | Total | Revenues | Total | ||||||||||||
Change in fair value | $ | -853 | $ | 171 | $ | -682 | $ | 0 | $ | -682 | |||||||
Reclassification to realized at | |||||||||||||||||
settlement | 93 | -141 | -48 | 0 | -48 | ||||||||||||
Net mark-to-market gains | |||||||||||||||||
(losses) | $ | -760 | $ | 30 | $ | -730 | $ | 0 | $ | -730 | |||||||
Exelon and Generation | Intercompany Eliminations | Exelon | |||||||||||||||
Purchased | |||||||||||||||||
Operating | Power | Operating | |||||||||||||||
Three Months Ended March 31, 2013 | Revenues | and Fuel | Total | Revenues (a) | Total | ||||||||||||
Change in fair value | $ | -485 | $ | 149 | $ | -336 | $ | 7 | $ | -329 | |||||||
Reclassification to realized at | |||||||||||||||||
settlement | -101 | 34 | -67 | 10 | -57 | ||||||||||||
Net mark-to-market gains | |||||||||||||||||
(losses) | $ | -586 | $ | 183 | $ | -403 | $ | 17 | $ | -386 | |||||||
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 were recorded to operating revenues and eliminated in consolidation. | |||||||||||||||||
Proprietary Trading Activities (Exelon and Generation). For the three months ended March 31, 2014 and 2013, 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 | |||||||||||||||||
Location on Income | March 31, | ||||||||||||||||
Statement | 2014 | 2013 | |||||||||||||||
Change in fair value | Operating Revenues | $ | -3 | $ | -4 | ||||||||||||
Reclassification to realized at settlement | Operating Revenues | 1 | 6 | ||||||||||||||
Net mark-to-market gains (losses) | Operating Revenues | $ | -2 | $ | 2 | ||||||||||||
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 March 31, 2014. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. The figures in the tables below 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 $34 million, $42 million and $41 million, respectively. | |||||||||||||||||
Total | Number of | Net Exposure of | |||||||||||||||
Exposure | Counterparties | Counterparties | |||||||||||||||
Before Credit | Credit | Net | Greater than 10% | Greater than 10% | |||||||||||||
Rating as of March 31, 2014 | Collateral | Collateral(a) | Exposure | of Net Exposure | of Net Exposure | ||||||||||||
Investment grade | $ | 1,182 | $ | 117 | $ | 1,065 | 1 | $ | 443 | ||||||||
Non-investment grade | 35 | 22 | 13 | 0 | 0 | ||||||||||||
No external ratings | |||||||||||||||||
Internally rated - investment grade | 321 | 0 | 321 | 1 | 206 | ||||||||||||
Internally rated - non-investment | |||||||||||||||||
grade | 32 | 9 | 23 | 0 | 0 | ||||||||||||
Total | $ | 1,570 | $ | 148 | $ | 1,422 | 2 | $ | 649 | ||||||||
Net Credit Exposure by Type of Counterparty | As of March 31, 2014 | ||||||||||||||||
Financial institutions | $ | 201 | |||||||||||||||
Investor-owned utilities, marketers, power producers | 392 | ||||||||||||||||
Energy cooperatives and municipalities | 799 | ||||||||||||||||
Other | 30 | ||||||||||||||||
Total | $ | 1,422 | |||||||||||||||
As of March 31, 2014, credit collateral held from counterparties where Generation had credit exposure included $140 million of cash and $8 million of letters of credit. | |||||||||||||||||
ComEd's power procurement contracts provide suppliers with a certain amount of unsecured credit. The credit position is based on forward market prices compared to the benchmark prices. The benchmark prices are the forward prices of energy projected through the contract term and are set at the point of supplier bid submittals. If the forward market price of energy exceeds the benchmark price, the suppliers are required to post collateral for the secured credit portion after adjusting for any unpaid deliveries and unsecured credit allowed under the contract. The unsecured credit used by the suppliers represents ComEd's net credit exposure. As of March 31, 2014, ComEd's credit exposure to suppliers was immaterial. | |||||||||||||||||
ComEd is permitted to recover its costs of procuring energy through the Illinois Settlement Legislation. ComEd's counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3 – Regulatory Matters of the Exelon 2013 Form 10-K for additional information. | |||||||||||||||||
PECO's supplier master agreements that govern the terms of its electric supply procurement contracts, which define a supplier's performance assurance requirements, allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier's lowest credit rating from the major credit rating agencies and the supplier's tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier's unsecured credit limit. The unsecured credit used by the suppliers represents PECO's net credit exposure. The unsecured credit used by the suppliers represents PECO's net credit exposure. As of March 31, 2014, PECO's net credit exposure with suppliers was immaterial and did not exceed the allowed unsecured credit levels. | |||||||||||||||||
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 4 - Regulatory Matters for additional information. | |||||||||||||||||
PECO's natural gas procurement plan is reviewed and approved annually on a prospective basis by the PAPUC. PECO's counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the PGC, which allows PECO to adjust rates quarterly to reflect realized natural gas prices. PECO does not obtain collateral from suppliers under its natural gas supply and asset management agreements. As of March 31, 2014, PECO had credit exposure of $1 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 4 - Regulatory Matters for additional information. | |||||||||||||||||
BGE's full requirement wholesale electric power agreements that govern the terms of its electric supply procurement contracts, which define a supplier's performance assurance requirements, allow a supplier, or its guarantor, to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier's lowest credit rating from the major credit rating agencies and the supplier's tangible net worth, subject to an unsecured credit cap. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier's unsecured credit limit. The unsecured credit used by the suppliers represents BGE's net credit exposure. The seller's credit exposure is calculated each business day. As of March 31, 2014, BGE had a net credit exposure of $18 million 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 March 31, 2014, BGE had credit exposure of $12 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 | March 31, | December 31, | |||||||||||||||
2014 | 2013 | ||||||||||||||||
Gross Fair Value of Derivative Contracts Containing this Feature(a) | $ | -1,178 | $ | -1,056 | |||||||||||||
Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements(b) | 902 | 846 | |||||||||||||||
Net Fair Value of Derivative Contracts Containing This Feature(c) | $ | -276 | $ | -210 | |||||||||||||
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 $713 million and letters of credit posted of $555 million and cash collateral held of $148 million and letters of credit held of $14 million as of March 31, 2014 for counterparties with derivative positions. Generation had cash collateral posted of $72 million and letters of credit posted of $364 million and cash collateral held of $206 million and letters of credit held of $34 million at December 31, 2013 for counterparties with derivative positions. In the event of a credit downgrade below investment grade (i.e., to BB+ by S&P or Ba1 by Moody's), Generation could be required to post additional collateral of $2.1 billion as of March 31, 2014 and $2.0 billion as of December 31, 2013. 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 March 31, 2014, Generation's and Exelon's swaps were in an asset position, with a fair value of $12 million and $21 million, respectively. | |||||||||||||||||
See Note 24 – Segment Information of the Exelon 2013 Form 10-K for further information regarding the letters of credit supporting the cash collateral. | |||||||||||||||||
Generation entered into supply forward contracts with certain utilities, including PECO and BGE, with one-sided collateral postings only from Generation. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded. Under the terms of ComEd's standard block energy contracts, collateral postings are one-sided from suppliers, including Generation, should exposures between market prices and benchmark prices exceed established unsecured credit limits outlined in the contracts. As of March 31, 2014, ComEd held neither cash nor letters of credit for the purpose of collateral from suppliers in association with energy procurement contracts. Under the terms of ComEd's annual renewable energy contracts, collateral postings are required to cover a fixed value for RECs only. In addition, under the terms of ComEd's long-term renewable energy contracts, collateral postings are required from suppliers for both RECs and energy. The REC portion is a fixed value and the energy portion is one-sided from suppliers should the forward market prices exceed contract prices. As of March 31, 2014, ComEd held approximately $19 million in the form of cash and letters of credit as margin for both the annual and long-term REC obligations. See Note 3 – Regulatory Matters of the Exelon 2013 Form 10-K for additional information. | |||||||||||||||||
PECO's natural gas procurement contracts contain provisions that could require PECO to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon PECO's credit rating from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. As of March 31, 2014, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of March 31, 2014, PECO could have been required to post approximately $43 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 March 31, 2014, BGE was not required to post collateral for any of these agreements. If BGE lost its investment grade credit rating as of March 31, 2014, BGE could have been required to post approximately $153 million of collateral to its counterparties. |
Debt_and_Credit_Agreements_Exe
Debt and Credit Agreements (Exelon, Generation, ComEd, PECO and BGE) | 3 Months Ended | ||||||||||
Mar. 31, 2014 | |||||||||||
Debt and Credit Agreements [Line Items] | ' | ||||||||||
Debt Disclosure [Text Block] | ' | ||||||||||
8. 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 March 31, 2014 and December 31, 2013: | |||||||||||
Commercial Paper Borrowings | 31-Mar-14 | 31-Dec-13 | |||||||||
Exelon Corporate | $ | 0 | $ | 0 | |||||||
Generation | 352 | 0 | |||||||||
ComEd | 534 | 184 | |||||||||
PECO | 0 | 0 | |||||||||
BGE | 69 | 135 | |||||||||
Credit Facilities | |||||||||||
Exelon had bank lines of credit under committed credit facilities at March 31, 2014 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-19 | 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 March 31, 2014, letters of credit issued under these agreements for Generation, ComEd, PECO and BGE totaled $20 million, $17 million, $21 million and $1 million, respectively. | |||||||||||
As of March 31, 2014, there were no borrowings under the Registrants' credit facilities. | |||||||||||
On March 28, 2014, ComEd extended for an additional year, its unsecured revolving credit facility with aggregate bank commitments of $1.0 billion. Under this facility, ComEd may issue letters of credit in the aggregate amount of up to $500 million. The credit agreement expires on March 28, 2019. The credit facility also allows ComEd to request increases in the aggregate commitments of up to an additional $500 million. Any increases are subject to the approval of the lenders party to the credit agreement in their sole discretion. Costs incurred to extend the facility for ComEd were not material. | |||||||||||
Borrowings under Exelon Corporate's, Generation's, ComEd's, PECO's and BGE's credit agreements bear interest at a rate based upon either the prime rate or a LIBOR-based rate, plus an adder based upon the particular registrant's credit rating. Exelon Corporate, Generation, ComEd, PECO and BGE have adders of 27.5, 27.5, 7.5, 0.0 and 0.0 basis points for prime based borrowings and 127.5, 127.5, 107.5, 90.0 and 100.0 basis points for LIBOR-based borrowings. The maximum adders for prime rate borrowings and LIBOR-based rate borrowings are 65 basis points and 165 basis points, respectively. The credit agreements also require the borrower to pay a facility fee based upon the aggregate commitments under the agreement. The fee varies depending upon the respective credit ratings of the borrower. | |||||||||||
Long-Term Debt | |||||||||||
Issuance of Long-Term Debt | |||||||||||
During the three months ended March 31, 2014, the following long-term debt was issued: | |||||||||||
Company | Type | Interest Rate | Maturity | Amount | Use of Proceeds | ||||||
Generation | ExGen Renewables I Project Financing | LIBOR + 4.250% | 6-Feb-21 | $ | 300 | Used for general corporate purposes | |||||
ComEd | Mortgage Bonds Series 115 | 2.15 | % | 15-Jan-19 | $ | 300 | Used to refinance existing mortgage bonds | ||||
ComEd | Mortgage Bonds Series 116 | 4.7 | % | 15-Jan-44 | $ | 350 | Used to refinance existing mortgage bonds | ||||
During the three months ended March 31, 2013, the following long-term debt was issued: | |||||||||||
Company | Type | Interest Rate | Maturity | Amount | Use of Proceeds | ||||||
Generation | Upstream Gas Lending Agreement | 2.21 | % | 22-Jul-16 | $ | 3 | Used to fund Upstream gas activities | ||||
Generation | DOE Project Financing | 2.720 - 2.810 | % | 5-Jan-37 | $ | 146 | Funding for Antelope Valley Solar Development | ||||
Retirement and Redemptions of Current and Long-Term Debt | |||||||||||
During the three months ended March 31, 2014, the following long-term debt was retired and/or redeemed: | |||||||||||
Company | Type | Interest Rate | Maturity | Amount | |||||||
Generation | 2003 Senior Notes | 5.35 | % | 15-Jan-14 | $ | 500 | |||||
Generation | Pollution Control Loan | 4.1 | % | 1-Jul-14 | $ | 20 | |||||
Generation | Continental Wind Project Financing | 6 | % | 28-Feb-33 | $ | 11 | |||||
Generation | Kennett Square Capital Lease | 7.83 | % | 20-Sep-20 | $ | 1 | |||||
ComEd | Mortgage Bonds Series 110 | 1.63 | % | 15-Jan-14 | $ | 600 | |||||
ComEd | Pollution Control Series 1994C | 5.85 | % | 15-Jan-14 | $ | 17 | |||||
During the three months ended March 31, 2013, the following long-term debt was retired and/or redeemed: | |||||||||||
Company | Type | Interest Rate | Maturity | Amount | |||||||
Generation | Kennett Square Capital Lease | 7.83 | % | 20-Sep-20 | $ | 1 | |||||
Non-Recourse Debt | |||||||||||
The following describes certain indebtedness that was incurred by Generation's project company subsidiaries during the three months ended March 31, 2014. The indebtedness described below is a component of the total net book value of certain generating facilities pledged as collateral of $1.9 billion as of March 31, 2014. All associated project financing liabilities are non-recourse to Exelon and Generation. | |||||||||||
ExGen Renewables Energy I LLC | |||||||||||
On February 6, 2014, ExGen Renewables I, LLC (EGR), an indirect subsidiary of Exelon and Generation, borrowed $300 million aggregate principal amount pursuant to a non-recourse senior secured loan, due February 6, 2021. The loan bears interest at a variable rate equal to LIBOR plus 4.25%. EGR indirectly owns Continental Wind LLC (Continental Wind). In addition to the financing, EGR entered into interest rate swaps with a notional amount of $240 million to manage a portion of the interest rate exposure in connection with the financing. See Note 7 – Derivative Financial Instruments for additional information regarding interest rate swaps. | |||||||||||
Income_Taxes_Exelon_Generation
Income Taxes (Exelon, Generation, ComEd, PECO and BGE) | 3 Months Ended | |||||||||||||||
Mar. 31, 2014 | ||||||||||||||||
Income Taxes [Line Items] | ' | |||||||||||||||
Income Taxes (Exelon, Generation, ComEd, PECO and BGE) | ' | |||||||||||||||
9. 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 March 31, 2014 | Exelon | Generation (a) | 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 | -57.6 | 9.7 | 5.5 | 1.2 | 5.2 | |||||||||||
Qualified nuclear decommissioning trust fund income | 44.2 | -4.6 | — | — | — | |||||||||||
Domestic production activities deduction | -27.8 | 2.9 | — | — | — | |||||||||||
Health care reform legislation | 1.3 | — | 0.1 | — | 0.2 | |||||||||||
Amortization of investment tax credit, net | ||||||||||||||||
deferred taxes | -18 | 1.7 | -0.3 | -0.1 | -0.2 | |||||||||||
Plant basis differences | -31.4 | — | -0.6 | -8.7 | -0.6 | |||||||||||
Production tax credits and other credits | -36.5 | 3.8 | — | — | — | |||||||||||
Other | -47.7 | 3.3 | 0.2 | 0.2 | 0.1 | |||||||||||
Effective income tax rate | -138.5 | % | 51.8 | % | 39.9 | % | 27.6 | % | 39.7 | % | ||||||
For the Three Months Ended March 31, 2013 | Exelon | Generation (b) | ComEd (b) | 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 | 68 | 82 | 5.8 | 2.8 | 5.7 | |||||||||||
Qualified nuclear decommissioning trust fund income | 62 | -192.3 | — | — | — | |||||||||||
Domestic production activities deduction | -2.4 | 7.4 | — | — | — | |||||||||||
Tax exempt income | -1.6 | 4.8 | — | — | — | |||||||||||
Health care reform legislation | 2.2 | — | -0.5 | — | 0.4 | |||||||||||
Amortization of investment tax credit, net | ||||||||||||||||
deferred taxes | -25.8 | 75.6 | 0.4 | -0.1 | -0.2 | |||||||||||
Plant basis differences | -24.9 | — | 0.9 | -6.7 | -0.6 | |||||||||||
Production tax credits and other credits | -21.7 | 67.2 | — | — | — | |||||||||||
Other | 7.4 | -74.1 | 0.1 | 0.1 | 0.4 | |||||||||||
Effective income tax rate | 98.2 | % | 5.6 | % | 41.7 | % | 31.1 | % | 40.7 | % | ||||||
_____ | ||||||||||||||||
(a) Generation recognized a loss before income taxes for the three months ended March 31, 2014. As a result, positive percentages represent an income tax benefit for Generation for the three months ended March 31, 2014 | ||||||||||||||||
Accounting for Uncertainty in Income Taxes | ||||||||||||||||
Exelon, Generation, ComEd, PECO, and BGE have $1,861 million, $1,394 million, $155 million, $44 million, and $0 million, of unrecognized tax benefits as of March 31, 2014, respectively, and $2,175 million, $1,415 million, $324 million, $44 million, and $0 million, of unrecognized tax benefits as of December 31, 2013, respectively. The unrecognized tax benefits as of March 31, 2014 reflect a decrease at Exelon and ComEd primarily attributable to the like-kind exchange and the lease termination position discussed below. | ||||||||||||||||
Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date | ||||||||||||||||
Nuclear Decommissioning Liabilities (Exelon and Generation) | ||||||||||||||||
AmerGen filed income tax refund claims taking the position that nuclear decommissioning liabilities assumed as part of its acquisition of nuclear power plants are taken into account in determining the tax basis in the assets it acquired. The additional basis results primarily in reduced capital gains or increased capital losses on the sale of assets in nonqualified decommissioning funds and increased tax depreciation and amortization deductions. The IRS disagrees with this position and has disallowed the claims. In November 2008, Generation received a final determination from the Appeals division of the IRS (IRS Appeals) disallowing AmerGen's refund claims. Generation filed a complaint in the United States Court of Federal Claims on February 20, 2009 to contest this determination. During the first and second quarters of 2013, AmerGen and the DOJ completed and filed cross motions for summary judgment. On September 17, 2013, the Court granted the government's motion denying AmerGen's claims for refund. In the first quarter of 2014, Exelon filed an appeal of the decision to the United States Court of Appeals for the Federal Circuit. | ||||||||||||||||
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 12 months. | ||||||||||||||||
Settlement of Income Tax Audits | ||||||||||||||||
As of March 31, 2014, Exelon and Generation have approximately $225 million of unrecognized state tax benefits that could significantly increase or decrease within the 12 months after the reporting date as a result of completing federal and state audits and expected statute of limitation expirations that if recognized would decrease the effective tax rate. In January 2014, certain unrecognized tax benefits as of December 31, 2013 were effectively settled and thus resulted in reduced tax expense of $33 million at Generation in the first quarter of 2014. | ||||||||||||||||
Other Income Tax Matters | ||||||||||||||||
Like-Kind Exchange | ||||||||||||||||
Exelon, through its ComEd subsidiary, took a position on its 1999 income tax return to defer approximately $1.2 billion of tax gain on the sale of ComEd's fossil generating assets. The gain was deferred by reinvesting a portion of the proceeds from the sale in qualifying replacement property under the like-kind exchange provisions of the IRC. The like-kind exchange replacement property purchased by Exelon included interests in three municipal-owned electric generation facilities which were properly leased back to the municipalities. The IRS disagreed with this position and asserted that the entire gain of approximately $1.2 billion was taxable in 1999. | ||||||||||||||||
Exelon has been unable to reach agreement with the IRS regarding the dispute over the like-kind exchange position. The IRS has asserted that the Exelon purchase and leaseback transaction is substantially similar to a leasing transaction, known as a SILO, which the IRS does not respect as the acquisition of an ownership interest in property. A SILO is a “listed transaction” that the IRS has identified as a potentially abusive tax shelter under guidance issued in 2005. Accordingly, the IRS has asserted that the sale of the fossil plants followed by the purchase and leaseback of the municipal owned generation facilities does not qualify as a like-kind exchange and the gain on the sale is fully subject to tax. The IRS has also asserted a penalty of approximately $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 unpaid tax liabilities related to the uncertain tax position, and the charges arising from future interest accruals are not expected to be material to the annual operating earnings of Exelon or ComEd. In addition, ComEd will continue to record non-cash equity contributions from Exelon in the amount of the net after-tax interest charges attributable to ComEd in connection with the like-kind exchange position. Exelon continues to believe that it is unlikely that the $87 million penalty assertion will ultimately be sustained and therefore no liability for the penalty has been recorded. | ||||||||||||||||
On September 30, 2013, the Internal Revenue Service issued a notice of deficiency to Exelon for the like-kind exchange position. Exelon filed a petition on December 13, 2013 to initiate litigation in the United States Tax Court. Exelon was not required to remit any part of the asserted tax or penalty in order to litigate the issue. The litigation could take three to five years including appeals, if necessary. Decisions in the Tax Court are not controlled by the Federal Circuit's decision in Consolidated Edison. | ||||||||||||||||
In the event of a fully successful IRS challenge to Exelon's like-kind exchange position, the potential tax and after-tax interest, exclusive of penalties, that could become currently payable as of March 31, 2014 may be as much as $840 million, of which approximately $300 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. | ||||||||||||||||
In the first quarter of 2014, Exelon entered into an agreement to terminate its investment in one of the three municipal-owned electric generation properties in exchange for a net early termination amount of $335 million. The termination will result in a 2014 tax payment of approximately $285 million by Exelon, including approximately $155 million by ComEd representing the remaining gain deferred pursuant to the like-kind exchange transaction. In the event of a fully successful IRS challenge to Exelon's like-kind exchange position, Exelon will be required to pay the full amount of tax and after-tax interest discussed in the preceding paragraph but will ultimately be entitled to a refund of the 2014 tax payment. See Note 16 – Supplemental Financial Information for further details. | ||||||||||||||||
Accounting for Final Tangible Property Regulations (Exelon, Generation, ComEd, PECO, and BGE) | ||||||||||||||||
On September 19, 2013, the Treasury Department and the IRS published final regulations regarding the tax treatment of costs incurred to acquire, produce, or improve tangible property. The Registrants have assessed the financial impact of this guidance and do not expect it to have a material impact. Any changes in method of accounting required to conform to the final regulations will be made for the Registrant's 2014 taxable year. | ||||||||||||||||
Accounting for Generation Repairs (Exelon and Generation) | ||||||||||||||||
On April 30, 2013, the IRS issued Revenue Procedure 2013-24 providing guidance for determining the appropriate tax treatment of costs incurred to repair electric generation assets. Generation will change its method of accounting for deducting repairs in accordance with this guidance beginning with its 2014 tax year. Generation has estimated that adoption of the new method will result in a cash tax detriment of approximately $100 - $120 million. | ||||||||||||||||
Long-Term State Tax Apportionment (Exelon and Generation) | ||||||||||||||||
Exelon and Generation periodically review events that may significantly impact how income is apportioned among the states and, therefore, the calculation of Exelon's and Generation's deferred state income taxes. As a result of the merger with Constellation, Exelon and Generation re-evaluated their long-term state tax apportionment in the first quarter of 2012. The total effect of revising the long-term state tax apportionment resulted in the recording of a deferred state tax asset of $72 million (net of Federal taxes) for Exelon. Of this, a benefit in the amount of $116 million and $14 million (net of Federal taxes) was recorded for Exelon and Generation, respectively, for the three months ended March 31, 2012. Further, Exelon and Generation recorded deferred state tax liabilities of $44 million and $14 million (net of Federal taxes), respectively, as part of purchase accounting during the three months ended March 31, 2012. The long-term state tax apportionment also was updated in the fourth quarter of 2012, resulting in the recording of a deferred state tax benefit of $3 million (net of Federal taxes) for Exelon, and a deferred state tax expense of $7 million (net of Federal taxes) for Generation. There was no change to the long-term state tax apportionment for BGE, ComEd and PECO. | ||||||||||||||||
The long-term state tax apportionment was revised in the fourth quarter of 2013 and in the first quarter of 2014, resulting in the recording of amounts that are immaterial for Exelon and Generation, respectively, for both periods. |
Asset_Retirement_Obligations_E
Asset Retirement Obligations (Exelon, Generation, ComEd and PECO) | 3 Months Ended | ||||||
Mar. 31, 2014 | |||||||
Asset Retirement Obligations [Line Items] | ' | ||||||
Asset Retirement Obligations (Exelon, Generation, ComEd and PECO) | ' | ||||||
10. 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, 2013 to March 31, 2014: | |||||||
Nuclear decommissioning ARO at December 31, 2013 (a) | $ | 4,855 | |||||
Accretion expense(a) | 66 | ||||||
Costs incurred to decommission retired plants | -1 | ||||||
Nuclear decommissioning ARO at March 31, 2014 (a) | $ | 4,920 | |||||
(a) Includes $9 million as the current portion of the ARO at March 31, 2014 and December 31, 2013 which is included in Other current liabilities on Exelon's and Generation's Consolidated Balance Sheets. | |||||||
Nuclear Decommissioning Trust Fund Investments | |||||||
NDT funds have been established for each generating station unit to satisfy Generation's nuclear decommissioning obligations. Generally, NDT funds established for a particular unit may not be used to fund the decommissioning obligations of any other unit. | |||||||
The NDT funds associated with 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 former PECO plants. The amounts collected from PECO customers are remitted to Generation and deposited into the NDT funds for the unit for which funds are collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO's calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. The most recent rate adjustment occurred on January 1, 2013, and the effective rates currently yield annual collections of approximately $24 million. The next five-year adjustment is expected to be reflected in rates charged to PECO customers effective January 1, 2018. 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, through PECO, has recourse to collect additional amounts from PECO customers related to a shortfall of NDT funds for the former PECO units, subject to certain limitations and thresholds, as prescribed by an order from the PAPUC. Generally, PECO, and likewise Generation, will not be allowed to collect amounts associated with the first $50 million of any shortfall of trust funds, 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 March 31, 2014 and December 31, 2013, Exelon and Generation had NDT fund investments totaling $8,215 million and $8,071 million, respectively. | |||||||
The following table provides unrealized gains on NDT funds for the three months ended March 31, 2014 and 2013: | |||||||
Three Months Ended | |||||||
March 31, | |||||||
2014 | 2013 | ||||||
Net unrealized gains on decommissioning trust funds — | |||||||
Regulatory Agreement Units (a) | $ | 61 | $ | 195 | |||
Net unrealized gains on decommissioning trust funds — | |||||||
Non-Regulatory Agreement Units (b)(c) | 13 | 64 | |||||
(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 $ 10 million and $2 million of net unrealized gains related to the Zion Station pledged assets for the three months ended March 31, 2014 and 2013, 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 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 25 – Related Party Transactions of the Exelon 2013 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. See Note 15 – Asset Retirement Obligations of the Exelon 2013 Form 10-K for information regarding the specific treatment of assets, including NDT funds, and decommissioning liabilities transferred in the transaction. | |||||||
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 for the SNF. Following ZionSolutions' completion of its contractual obligations, Generation will store the SNF at Zion Station until it is transferred to the DOE for ultimate disposal and will complete all remaining decommissioning activities associated with the SNF dry storage facility. Generation has a liability of approximately $84 million, which is included within the nuclear decommissioning ARO at March 31, 2014. 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 March 31, 2014 and December 31, 2013: | |||||||
Exelon and Generation | |||||||
March 31, | December 31, | ||||||
2014 | 2013 | ||||||
Carrying value of Zion Station pledged assets | $ | 429 | $ | 458 | |||
Payable to Zion Solutions (a) | 385 | 414 | |||||
Current portion of payable to Zion Solutions (b) | 103 | 109 | |||||
Withdrawals by Zion Solutions to pay decommissioning costs (c) | 537 | 498 | |||||
__________ | |||||||
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 March 31, 2014, Generation submitted its NRC required annual decommissioning funding report as of December 31, 2013 for shutdown reactors. This submittal also included the required updated financial tests for the Limerick Unit 1 parent guarantee. There was no change to the amount of the parent guarantee, or the funding status of these reactors. Adequate decommissioning funding assurance is in place for all reactors owned by Generation. | |||||||
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. On April 7, 2014, Generation received a request for additional detail related to information Generation provided during the pre-decisional enforcement conference. Generation is in the process of collecting and providing the additional detail. Generation does not have a definite date on which it will receive a response from the NRC, but anticipates that the NRC will issue its findings sometime this year. 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. | |||||||
In addition, on June 24, 2013, Exelon received a subpoena from the SEC requesting that Exelon provide the SEC with certain documents generally relating to Exelon and Generation's reporting and funding of the future decommissioning of Generation's nuclear power plants. Exelon and Generation have cooperated with the SEC and provided the requested documents. On February 13, 2014, Exelon received a letter from the SEC confirming that it had concluded its investigation and that no further action was anticipated based on information provided by Exelon. | |||||||
Exelon Generation Co L L C [Member] | ' | ||||||
Asset Retirement Obligations [Line Items] | ' | ||||||
Asset Retirement Obligations (Exelon, Generation, ComEd and PECO) | ' | ||||||
10. 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, 2013 to March 31, 2014: | |||||||
Nuclear decommissioning ARO at December 31, 2013 (a) | $ | 4,855 | |||||
Accretion expense(a) | 66 | ||||||
Costs incurred to decommission retired plants | -1 | ||||||
Nuclear decommissioning ARO at March 31, 2014 (a) | $ | 4,920 | |||||
Three Months Ended | |||||||
March 31, | |||||||
2014 | 2013 | ||||||
Net unrealized gains on decommissioning trust funds — | |||||||
Regulatory Agreement Units (a) | $ | 61 | $ | 195 | |||
Net unrealized gains on decommissioning trust funds — | |||||||
Non-Regulatory Agreement Units (b)(c) | 13 | 64 | |||||
(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 $ 10 million and $2 million of net unrealized gains related to the Zion Station pledged assets for the three months ended March 31, 2014 and 2013, 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 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 25 – Related Party Transactions of the Exelon 2013 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. See Note 15 – Asset Retirement Obligations of the Exelon 2013 Form 10-K for information regarding the specific treatment of assets, including NDT funds, and decommissioning liabilities transferred in the transaction. | |||||||
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 for the SNF. Following ZionSolutions' completion of its contractual obligations, Generation will store the SNF at Zion Station until it is transferred to the DOE for ultimate disposal and will complete all remaining decommissioning activities associated with the SNF dry storage facility. Generation has a liability of approximately $84 million, which is included within the nuclear decommissioning ARO at March 31, 2014. 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 March 31, 2014 and December 31, 2013: | |||||||
Exelon and Generation | |||||||
March 31, | December 31, | ||||||
2014 | 2013 | ||||||
Carrying value of Zion Station pledged assets | $ | 429 | $ | 458 | |||
Payable to Zion Solutions (a) | 385 | 414 | |||||
Current portion of payable to Zion Solutions (b) | 103 | 109 | |||||
Withdrawals by Zion Solutions to pay decommissioning costs (c) | 537 | 498 | |||||
__________ | |||||||
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 March 31, 2014, Generation submitted its NRC required annual decommissioning funding report as of December 31, 2013 for shutdown reactors. This submittal also included the required updated financial tests for the Limerick Unit 1 parent guarantee. There was no change to the amount of the parent guarantee, or the funding status of these reactors. Adequate decommissioning funding assurance is in place for all reactors owned by Generation. | |||||||
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. On April 7, 2014, Generation received a request for additional detail related to information Generation provided during the pre-decisional enforcement conference. Generation is in the process of collecting and providing the additional detail. Generation does not have a definite date on which it will receive a response from the NRC, but anticipates that the NRC will issue its findings sometime this year. 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. | |||||||
In addition, on June 24, 2013, Exelon received a subpoena from the SEC requesting that Exelon provide the SEC with certain documents generally relating to Exelon and Generation's reporting and funding of the future decommissioning of Generation's nuclear power plants. Exelon and Generation have cooperated with the SEC and provided the requested documents. On February 13, 2014, Exelon received a letter from the SEC confirming that it had concluded its investigation and that no further action was anticipated based on information provided by Exelon. | |||||||
Nuclear_Decommissioning_Exelon
Nuclear Decommissioning (Exelon and Generation) | 3 Months Ended | ||||||
Mar. 31, 2014 | |||||||
Nuclear Decommissioning Disclosure [Line Items] | ' | ||||||
Nuclear Decommissioning (Exelon and Generation) | ' | ||||||
10. 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, 2013 to March 31, 2014: | |||||||
Nuclear decommissioning ARO at December 31, 2013 (a) | $ | 4,855 | |||||
Accretion expense(a) | 66 | ||||||
Costs incurred to decommission retired plants | -1 | ||||||
Nuclear decommissioning ARO at March 31, 2014 (a) | $ | 4,920 | |||||
(a) Includes $9 million as the current portion of the ARO at March 31, 2014 and December 31, 2013 which is included in Other current liabilities on Exelon's and Generation's Consolidated Balance Sheets. | |||||||
Nuclear Decommissioning Trust Fund Investments | |||||||
NDT funds have been established for each generating station unit to satisfy Generation's nuclear decommissioning obligations. Generally, NDT funds established for a particular unit may not be used to fund the decommissioning obligations of any other unit. | |||||||
The NDT funds associated with 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 former PECO plants. The amounts collected from PECO customers are remitted to Generation and deposited into the NDT funds for the unit for which funds are collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO's calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. The most recent rate adjustment occurred on January 1, 2013, and the effective rates currently yield annual collections of approximately $24 million. The next five-year adjustment is expected to be reflected in rates charged to PECO customers effective January 1, 2018. 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, through PECO, has recourse to collect additional amounts from PECO customers related to a shortfall of NDT funds for the former PECO units, subject to certain limitations and thresholds, as prescribed by an order from the PAPUC. Generally, PECO, and likewise Generation, will not be allowed to collect amounts associated with the first $50 million of any shortfall of trust funds, 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 March 31, 2014 and December 31, 2013, Exelon and Generation had NDT fund investments totaling $8,215 million and $8,071 million, respectively. | |||||||
The following table provides unrealized gains on NDT funds for the three months ended March 31, 2014 and 2013: | |||||||
Three Months Ended | |||||||
March 31, | |||||||
2014 | 2013 | ||||||
Net unrealized gains on decommissioning trust funds — | |||||||
Regulatory Agreement Units (a) | $ | 61 | $ | 195 | |||
Net unrealized gains on decommissioning trust funds — | |||||||
Non-Regulatory Agreement Units (b)(c) | 13 | 64 | |||||
(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 $ 10 million and $2 million of net unrealized gains related to the Zion Station pledged assets for the three months ended March 31, 2014 and 2013, 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 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 25 – Related Party Transactions of the Exelon 2013 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. See Note 15 – Asset Retirement Obligations of the Exelon 2013 Form 10-K for information regarding the specific treatment of assets, including NDT funds, and decommissioning liabilities transferred in the transaction. | |||||||
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 for the SNF. Following ZionSolutions' completion of its contractual obligations, Generation will store the SNF at Zion Station until it is transferred to the DOE for ultimate disposal and will complete all remaining decommissioning activities associated with the SNF dry storage facility. Generation has a liability of approximately $84 million, which is included within the nuclear decommissioning ARO at March 31, 2014. 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 March 31, 2014 and December 31, 2013: | |||||||
Exelon and Generation | |||||||
March 31, | December 31, | ||||||
2014 | 2013 | ||||||
Carrying value of Zion Station pledged assets | $ | 429 | $ | 458 | |||
Payable to Zion Solutions (a) | 385 | 414 | |||||
Current portion of payable to Zion Solutions (b) | 103 | 109 | |||||
Withdrawals by Zion Solutions to pay decommissioning costs (c) | 537 | 498 | |||||
__________ | |||||||
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 March 31, 2014, Generation submitted its NRC required annual decommissioning funding report as of December 31, 2013 for shutdown reactors. This submittal also included the required updated financial tests for the Limerick Unit 1 parent guarantee. There was no change to the amount of the parent guarantee, or the funding status of these reactors. Adequate decommissioning funding assurance is in place for all reactors owned by Generation. | |||||||
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. On April 7, 2014, Generation received a request for additional detail related to information Generation provided during the pre-decisional enforcement conference. Generation is in the process of collecting and providing the additional detail. Generation does not have a definite date on which it will receive a response from the NRC, but anticipates that the NRC will issue its findings sometime this year. 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. | |||||||
In addition, on June 24, 2013, Exelon received a subpoena from the SEC requesting that Exelon provide the SEC with certain documents generally relating to Exelon and Generation's reporting and funding of the future decommissioning of Generation's nuclear power plants. Exelon and Generation have cooperated with the SEC and provided the requested documents. On February 13, 2014, Exelon received a letter from the SEC confirming that it had concluded its investigation and that no further action was anticipated based on information provided by Exelon. | |||||||
Exelon Generation Co L L C [Member] | ' | ||||||
Nuclear Decommissioning Disclosure [Line Items] | ' | ||||||
Nuclear Decommissioning (Exelon and Generation) | ' | ||||||
10. 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, 2013 to March 31, 2014: | |||||||
Nuclear decommissioning ARO at December 31, 2013 (a) | $ | 4,855 | |||||
Accretion expense(a) | 66 | ||||||
Costs incurred to decommission retired plants | -1 | ||||||
Nuclear decommissioning ARO at March 31, 2014 (a) | $ | 4,920 | |||||
Three Months Ended | |||||||
March 31, | |||||||
2014 | 2013 | ||||||
Net unrealized gains on decommissioning trust funds — | |||||||
Regulatory Agreement Units (a) | $ | 61 | $ | 195 | |||
Net unrealized gains on decommissioning trust funds — | |||||||
Non-Regulatory Agreement Units (b)(c) | 13 | 64 | |||||
(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 $ 10 million and $2 million of net unrealized gains related to the Zion Station pledged assets for the three months ended March 31, 2014 and 2013, 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 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 25 – Related Party Transactions of the Exelon 2013 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. See Note 15 – Asset Retirement Obligations of the Exelon 2013 Form 10-K for information regarding the specific treatment of assets, including NDT funds, and decommissioning liabilities transferred in the transaction. | |||||||
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 for the SNF. Following ZionSolutions' completion of its contractual obligations, Generation will store the SNF at Zion Station until it is transferred to the DOE for ultimate disposal and will complete all remaining decommissioning activities associated with the SNF dry storage facility. Generation has a liability of approximately $84 million, which is included within the nuclear decommissioning ARO at March 31, 2014. 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 March 31, 2014 and December 31, 2013: | |||||||
Exelon and Generation | |||||||
March 31, | December 31, | ||||||
2014 | 2013 | ||||||
Carrying value of Zion Station pledged assets | $ | 429 | $ | 458 | |||
Payable to Zion Solutions (a) | 385 | 414 | |||||
Current portion of payable to Zion Solutions (b) | 103 | 109 | |||||
Withdrawals by Zion Solutions to pay decommissioning costs (c) | 537 | 498 | |||||
__________ | |||||||
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 March 31, 2014, Generation submitted its NRC required annual decommissioning funding report as of December 31, 2013 for shutdown reactors. This submittal also included the required updated financial tests for the Limerick Unit 1 parent guarantee. There was no change to the amount of the parent guarantee, or the funding status of these reactors. Adequate decommissioning funding assurance is in place for all reactors owned by Generation. | |||||||
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. On April 7, 2014, Generation received a request for additional detail related to information Generation provided during the pre-decisional enforcement conference. Generation is in the process of collecting and providing the additional detail. Generation does not have a definite date on which it will receive a response from the NRC, but anticipates that the NRC will issue its findings sometime this year. 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. | |||||||
In addition, on June 24, 2013, Exelon received a subpoena from the SEC requesting that Exelon provide the SEC with certain documents generally relating to Exelon and Generation's reporting and funding of the future decommissioning of Generation's nuclear power plants. Exelon and Generation have cooperated with the SEC and provided the requested documents. On February 13, 2014, Exelon received a letter from the SEC confirming that it had concluded its investigation and that no further action was anticipated based on information provided by Exelon. | |||||||
Retirement_Benefits_Exelon_Gen
Retirement Benefits (Exelon, Generation, ComEd, PECO and BGE) | 3 Months Ended | ||||||||||||
Mar. 31, 2014 | |||||||||||||
Retirement Benefits [Line Items] | ' | ||||||||||||
Retirement Benefits (Exelon, Generation, ComEd, PECO and BGE) | ' | ||||||||||||
11. 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 2014, Exelon received an updated valuation of several of its pension and other postretirement benefit obligations to reflect actual census data as of January 1, 2014. This valuation resulted in an increase to the pension obligation of $35 million and an increase to the other postretirement benefit obligation of $12 million. Additionally, accumulated other comprehensive loss increased by approximately $13 million (after tax), regulatory assets increased by approximately $34 million, and regulatory liabilities increased by approximately $5 million. The updated valuation for the remainder of the plans will be completed in the second quarter of 2014. | |||||||||||||
In April 2014, Exelon announced plan design changes for certain OPEB plans, which will require an interim remeasurement of the benefit obligation for those plans using assumptions as of April 30, 2014, including updated discount rates. The plan design changes are estimated to result in a decrease in the net periodic benefit costs for OPEB of approximately $125 million for the period May 2014 through December 2014, a reduction of the OPEB obligation of approximately $800 million and changes to AOCI, regulatory assets and regulatory liabilities upon remeasurement, based on the December 31, 2013 valuation assumptions. The actual financial statement impacts are dependent on the economic assumptions at the April 30, 2014 remeasurement date. The plan design changes did not impact the March 31, 2014 results of operations, cash flows or financial position. Management is evaluating funding options for the OPEB plans, including implications of the plan design changes discussed above, which may result in reductions to the expected contributions. | |||||||||||||
The following tables present the components of Exelon's net periodic benefit costs for the three months ended March 31, 2014 and 2013. The 2014 pension benefit cost for all plans is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 4.80%. The 2014 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 6.59% for funded plans and a discount rate of 4.90% for all plans. Certain other postretirement benefit plans are not funded. A portion of the net periodic benefit cost is capitalized within the Consolidated Balance Sheets. | |||||||||||||
Other | |||||||||||||
Pension Benefits | Postretirement Benefits | ||||||||||||
Three Months Ended | Three Months Ended | ||||||||||||
March 31, | March 31, | ||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||
Service cost | $ | 69 | $ | 80 | $ | 33 | $ | 41 | |||||
Interest cost | 183 | 163 | 55 | 48 | |||||||||
Expected return on assets | -241 | -253 | -38 | -33 | |||||||||
Amortization of: | |||||||||||||
Prior service cost (benefit) | 3 | 3 | -4 | -4 | |||||||||
Actuarial loss | 105 | 140 | 8 | 20 | |||||||||
Net periodic benefit cost | $ | 119 | $ | 133 | $ | 54 | $ | 72 | |||||
The amounts below represent Generation's, ComEd's, PECO's, BGE's and BSC's allocated portion of the pension and postretirement benefit plan costs, which were included in Capital expenditures and Operating and maintenance expense during the three months ended March 31, 2014 and 2013. | |||||||||||||
Three Months Ended March 31, | |||||||||||||
Pension and Other Postretirement Benefit Costs | 2014 | 2013 | |||||||||||
Generation | $ | 75 | $ | 87 | |||||||||
ComEd | 56 | 77 | |||||||||||
PECO | 12 | 11 | |||||||||||
BGE | 16 | 13 | |||||||||||
BSC(a) | 14 | 17 | |||||||||||
(a) These amounts primarily represent amounts billed to Exelon's subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO or BGE amounts above. | |||||||||||||
Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006, management of the pension obligation and regulatory implications. Exelon expects to contribute $264 million to its qualified pension plans in 2014, of which Generation, ComEd, PECO and BGE will contribute $118 million, $119 million, $11 million and $0 million, respectively. Unlike the qualified pension plans, Exelon's non-qualified pension plans are not funded. Exelon expects to make non-qualified pension plan benefit payments of $12 million in 2014, of which Generation, ComEd, PECO and BGE will make payments of $5 million, $1 million, $0 million and $1 million, respectively. | |||||||||||||
Unlike qualified pension plans, other postretirement plans are not subject to statutory minimum contribution requirements. Exelon's management has historically considered several factors in determining the level of contributions to its other postretirement benefit plans, including levels of benefit claims paid and regulatory implications (amounts deemed prudent to meet regulator expectations and best assure continued rate recovery). Exelon expects to make other postretirement benefit plan contributions, including benefit payments related to unfunded plans, of approximately $430 million in 2014, of which Generation, ComEd, PECO and BGE expect to contribute $168 million, $197 million, $19 million and $17 million, respectively. Management is evaluating funding options for the other postretirement benefit plans, including implications of the plan design changes discussed above, which may result in reductions to the expected contributions. | |||||||||||||
Plan Assets | |||||||||||||
Investment Strategy. On a regular basis, Exelon evaluates its investment strategy to ensure that plan assets will be sufficient to pay plan benefits when due. As part of this ongoing evaluation, Exelon may make changes to its targeted asset allocation and investment strategy. | |||||||||||||
Exelon has developed and implemented a liability hedging investment strategy for its qualified pension plans that has reduced the volatility of its pension assets relative to its pension liabilities. Exelon is likely to continue to gradually increase the liability hedging portfolio as the funded status of its plans improves. The overall objective is to achieve attractive risk-adjusted returns that will balance the liquidity requirements of the plans' liabilities while striving to minimize the risk of significant losses. Trust assets for Exelon's other postretirement plans are managed in a diversified investment strategy that prioritizes maximizing liquidity and returns while minimizing asset volatility. | |||||||||||||
Defined Contribution Savings Plans | |||||||||||||
The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the IRC and allow employees to contribute a portion of their pre-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents the matching contributions to the savings plans during the three months ended March 31, 2014 and 2013: | |||||||||||||
Three Months Ended March 31, | |||||||||||||
Savings Plan Matching Contributions | 2014 | 2013 | |||||||||||
Exelon | $ | 29 | $ | 22 | |||||||||
Generation | 14 | 11 | |||||||||||
ComEd | 7 | 5 | |||||||||||
PECO | 2 | 2 | |||||||||||
BGE | 3 | 2 | |||||||||||
BSC(a) | 3 | 2 | |||||||||||
These amounts primarily represent amounts billed to Exelon's subsidiaries through intercompany allocations. These costs are not included in the Generation, ComEd, PECO or BGE amounts above. | |||||||||||||
Severance_And_Plants_Retiremen
Severance And Plants Retirements (exelon and Generation) | 3 Months Ended | ||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||
Restructuring Charges [Abstract] | ' | ||||||||||||||||
Corporate Restructuring and Plant Retirements (Exelon, Generation, ComEd and PECO) | ' | ||||||||||||||||
12. Severance (Exelon, Generation, ComEd, PECO and BGE) | |||||||||||||||||
The Registrants have an ongoing severance plan under which, in general, employees receive severance benefits based on their years of service. 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 their ongoing severance plan, the Registrants measure the obligation and record the expense at fair value at the communication date if there are no future service requirements, or, if future service is required to receive the termination benefit, ratably over the required service period. | |||||||||||||||||
Merger-Related Severance | |||||||||||||||||
Upon closing the merger with Constellation, Exelon recorded a severance accrual for anticipated employee position reductions as a result of the post-merger integration. The majority of these positions are corporate and Generation support positions. Since then, Exelon has identified specific employees to be severed pursuant to the merger-related staffing and selection process as well as employees that were previously identified for severance but have since accepted another position within Exelon and are no longer receiving a severance benefit. Exelon adjusts its accrual each quarter to reflect its best estimate of remaining severance costs. | |||||||||||||||||
The amount of severance expense associated with the post-merger integration recognized for the three months ended March 31, 2014 and 2013 is not material. Estimated costs to be incurred after March 31, 2014 are not material. | |||||||||||||||||
Amounts included in the table below represent the severance liability recorded by Exelon, Generation, ComEd, PECO and BGE for employees of those Registrants and exclude amounts billed through intercompany allocations: | |||||||||||||||||
Severance Liability | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||
Balance at December 31, 2013 | $ | 53 | $ | 10 | $ | 0 | $ | 0 | $ | 6 | |||||||
Payments | -12 | -1 | 0 | 0 | -2 | ||||||||||||
Balance at March 31, 2014 | $ | 41 | $ | 9 | $ | 0 | $ | 0 | $ | 4 | |||||||
Substantially all cash payments under the plan are expected to be made by the end of 2016. | |||||||||||||||||
Ongoing Severance Plans | |||||||||||||||||
The Registrants provide severance and health and welfare benefits under Exelon's ongoing severance benefit plans to terminated employees in the normal course of business. These benefits are accrued for when the benefits are considered probable and can be reasonably estimated. | |||||||||||||||||
For the three months ended March 31, 2014 and 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 and Comprehensive Income: | |||||||||||||||||
Severance Benefits | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||
Severance charges - 2014 | $ | 4 | $ | 4 | $ | 0 | $ | 0 | $ | 0 | |||||||
Severance charges - 2013 | 1 | 0 | 1 | 0 | 0 | ||||||||||||
The severance liability balances associated with these ongoing severance benefits as of March 31, 2014 and December 31, 2013 are not material. |
StockBased_Compensation_Plans_
Stock-Based Compensation Plans (Exelon, Generation, ComEd, PECO and BGE) | 3 Months Ended |
Mar. 31, 2014 | |
Stock-Based Compensation Plans [Line Items] | ' |
Stock-Based Compensation Plans (Exelon, Generation, ComEd, PECO and BGE) | ' |
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. | |
Changes_in_Accumulated_Other_C
Changes in Accumulated Other Comprehensive Income (Exelon, Generation, ComEd, PECO and BGE) | 3 Months Ended | ||||||||||||||||||||||||||||
Mar. 31, 2014 | Mar. 31, 2013 | ||||||||||||||||||||||||||||
Accumulated Other Comprehensive Income Loss [Line Items] | ' | ' | |||||||||||||||||||||||||||
Accumulated Other Comprehensive Income Loss [Text Block] | ' | [1] | ' | ||||||||||||||||||||||||||
For the Three Months Ended March 31, 2014 | 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 | 13. Changes in Accumulated Other Comprehensive Income (Exelon, Generation, and PECO) | ||||||||||||||||||||||
Exelon (a) | |||||||||||||||||||||||||||||
Beginning balance | $ | 120 | $ | 2 | $ | -2,260 | $ | -10 | $ | 108 | $ | -2,040 | The following tables present changes in accumulated other comprehensive income (loss) (AOCI) by component for the three months ended March 31, 2014 and 2013: | ||||||||||||||||
OCI before reclassifications | -1 | 0 | -13 | -5 | 11 | -8 | For the Three Months Ended March 31, 2013 | Gains and (Losses) on Cash Flow Hedges | Unrealized Gains and (Losses) on Marketable Securities | Pension and Non-Pension Postretirement Benefit Plan items | Foreign Currency Items | AOCI of Equity Investments | Total | ||||||||||||||||
Amounts reclassified from AOCI (b) | -24 | 0 | 35 | 0 | 1 | 12 | Exelon (a) | ||||||||||||||||||||||
Net current-period OCI | -25 | 0 | 22 | -5 | 12 | 4 | Beginning balance | $ | 368 | $ | 0 | $ | -3,137 | $ | 0 | $ | 2 | $ | -2,767 | ||||||||||
Ending balance | $ | 95 | $ | 2 | $ | -2,238 | $ | -15 | $ | 120 | $ | -2,036 | OCI before reclassifications | 0 | -1 | 76 | -1 | 26 | 100 | ||||||||||
Amounts reclassified from AOCI (b) | -58 | 0 | 50 | 0 | 2 | -6 | |||||||||||||||||||||||
Generation (a) | Net current-period OCI | -58 | -1 | 126 | -1 | 28 | 94 | ||||||||||||||||||||||
Beginning balance | $ | 114 | $ | 2 | $ | 0 | $ | -10 | $ | 108 | $ | 214 | Ending balance | $ | 310 | $ | -1 | $ | -3,011 | $ | -1 | $ | 30 | $ | -2,673 | ||||
OCI before reclassifications | -1 | -3 | 0 | -5 | 11 | 2 | |||||||||||||||||||||||
Amounts reclassified from AOCI (b) | -24 | 0 | 0 | 0 | 1 | -23 | Generation (a) | ||||||||||||||||||||||
Net current-period OCI | -25 | -3 | 0 | -5 | 12 | -21 | Beginning balance | $ | 513 | $ | -1 | $ | -19 | $ | 0 | $ | 20 | $ | 513 | ||||||||||
Ending balance | $ | 89 | $ | -1 | $ | 0 | $ | -15 | $ | 120 | $ | 193 | OCI before reclassifications | 5 | -1 | 0 | -1 | 26 | 29 | ||||||||||
Amounts reclassified from AOCI (b) | -135 | 0 | 0 | 0 | 2 | -133 | |||||||||||||||||||||||
ComEd (a) | Net current-period OCI | -130 | -1 | 0 | -1 | 28 | -104 | ||||||||||||||||||||||
Ending balance | $ | 383 | $ | -2 | $ | -19 | $ | -1 | $ | 48 | $ | 409 | |||||||||||||||||
PECO (a) | |||||||||||||||||||||||||||||
Beginning balance | $ | 0 | $ | 1 | $ | 0 | $ | 0 | $ | 0 | $ | 1 | ComEd (a) | ||||||||||||||||
OCI before reclassifications | 0 | 0 | 0 | 0 | 0 | 0 | |||||||||||||||||||||||
Amounts reclassified from AOCI (b) | 0 | 0 | 0 | 0 | 0 | 0 | PECO (a) | ||||||||||||||||||||||
Net current-period OCI | 0 | 0 | 0 | 0 | 0 | 0 | Beginning balance | $ | 0 | $ | 1 | $ | 0 | $ | 0 | $ | 0 | $ | 1 | ||||||||||
Ending balance | $ | 0 | $ | 1 | $ | 0 | $ | 0 | $ | 0 | $ | 1 | OCI before reclassifications | 0 | 0 | 0 | 0 | 0 | 0 | ||||||||||
Amounts reclassified from AOCI (b) | 0 | 0 | 0 | 0 | 0 | 0 | |||||||||||||||||||||||
BGE (a) | Net current-period OCI | 0 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||
Ending balance | $ | 0 | $ | 1 | $ | 0 | $ | 0 | $ | 0 | $ | 1 | |||||||||||||||||
(a) All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income. | |||||||||||||||||||||||||||||
(b) See tables following changes in accumulated other comprehensive income tables for details about these reclassifications. | BGE (a) | ||||||||||||||||||||||||||||
Three Months Ended March 31, 2014 | |||||||||||||||||||||||||||||
Details about AOCI components | Items reclassified out of AOCI (a) | Affected line item in the statement where Net Income is presented | |||||||||||||||||||||||||||
Exelon | Generation | ||||||||||||||||||||||||||||
Gains on cash flow hedges | |||||||||||||||||||||||||||||
Energy related hedges | $ | 39 | $ | 39 | Operating revenues | ||||||||||||||||||||||||
39 | 39 | Total before tax | |||||||||||||||||||||||||||
-15 | -15 | Tax (expense) | |||||||||||||||||||||||||||
$ | 24 | $ | 24 | Net of tax | |||||||||||||||||||||||||
Gains and (losses) on available for sale securities | |||||||||||||||||||||||||||||
Amortization of pension and other postretirement benefit plan items | |||||||||||||||||||||||||||||
Prior service costs | $ | -2 | $ | 0 | (b) | ||||||||||||||||||||||||
Actuarial losses | -56 | 0 | (b) | ||||||||||||||||||||||||||
-58 | 0 | Total before tax | |||||||||||||||||||||||||||
23 | 0 | Tax benefit | |||||||||||||||||||||||||||
$ | -35 | $ | 0 | Net of tax | |||||||||||||||||||||||||
Equity investments | |||||||||||||||||||||||||||||
Capital activity | $ | -1 | $ | -1 | Equity in losses of unconsolidated affiliates | ||||||||||||||||||||||||
-1 | -1 | Total before tax | |||||||||||||||||||||||||||
0 | 0 | Tax benefit | |||||||||||||||||||||||||||
$ | -1 | $ | -1 | Net of tax | |||||||||||||||||||||||||
Total Reclassifications | |||||||||||||||||||||||||||||
for the period | $ | -12 | $ | 23 | Net of Tax | ||||||||||||||||||||||||
Three Months Ended March 31, 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 on cash flow hedges | |||||||||||||||||||||||||||||
Energy related hedges | $ | 99 | $ | 223 | Operating revenues | ||||||||||||||||||||||||
Other cash flow hedges | -1 | 0 | Interest expense | ||||||||||||||||||||||||||
98 | 223 | Total before tax | |||||||||||||||||||||||||||
-40 | -88 | Tax (expense) | |||||||||||||||||||||||||||
$ | 58 | $ | 135 | Net of tax | |||||||||||||||||||||||||
Gains and (losses) on available for sale securities | |||||||||||||||||||||||||||||
Amortization of pension and other postretirement benefit plan items | |||||||||||||||||||||||||||||
Actuarial losses | $ | -83 | $ | 0 | (b) | ||||||||||||||||||||||||
-83 | 0 | Total before tax | |||||||||||||||||||||||||||
33 | 0 | Tax benefit | |||||||||||||||||||||||||||
$ | -50 | $ | 0 | Net of tax | |||||||||||||||||||||||||
Equity investments | |||||||||||||||||||||||||||||
Capital activity | $ | -3 | $ | -3 | Equity in losses of unconsolidated affiliates | ||||||||||||||||||||||||
-3 | -3 | Total before tax | |||||||||||||||||||||||||||
1 | 1 | Tax benefit | |||||||||||||||||||||||||||
$ | -2 | $ | -2 | Net of tax | |||||||||||||||||||||||||
Total Reclassifications | |||||||||||||||||||||||||||||
for the period | $ | 6 | $ | 133 | 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 11 for additional details). | |||||||||||||||||||||||||||||
Three Months Ended | |||||||||||||||||||||||||||||
March 31, | |||||||||||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||||||||||
Exelon | |||||||||||||||||||||||||||||
Pension and non-pension postretirement benefit plans: | |||||||||||||||||||||||||||||
Prior service benefit reclassified to periodic benefit cost | $ | -1 | $ | 0 | |||||||||||||||||||||||||
Actuarial loss reclassified to periodic cost | -23 | -32 | |||||||||||||||||||||||||||
Pension and non-pension postretirement benefit plans valuation | |||||||||||||||||||||||||||||
adjustment | 7 | -49 | |||||||||||||||||||||||||||
Change in unrealized loss on cash flow hedges | 18 | 33 | |||||||||||||||||||||||||||
Change in unrealized income on equity investments | -7 | -18 | |||||||||||||||||||||||||||
Total | $ | -6 | $ | -66 | |||||||||||||||||||||||||
Generation | |||||||||||||||||||||||||||||
Change in unrealized gain (loss) on cash flow hedges | $ | 19 | $ | 86 | |||||||||||||||||||||||||
Change in unrealized income on equity investments | -7 | -18 | |||||||||||||||||||||||||||
Change in unrealized loss on marketable securities | -2 | 0 | |||||||||||||||||||||||||||
Total | $ | 10 | $ | 68 | |||||||||||||||||||||||||
[1] | (a) All amounts are net of tax. Amounts in parenthesis represent a decrease in net income. |
Common_Stock_Exelon_Generation
Common Stock (Exelon, Generation, ComEd, PECO and BGE) | 3 Months Ended |
Mar. 31, 2014 | |
Common Stock [Line Items] | ' |
Stock-Based Compensation Plans (Exelon, Generation, ComEd, PECO and BGE) | ' |
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. | |
Earnings_Per_Share_and_Equity_
Earnings Per Share and Equity (Exelon) | 3 Months Ended | ||||||
Mar. 31, 2014 | |||||||
Earnings Per Share and Equity [Abstract] | ' | ||||||
Earnings Per Share and Equity (Exelon) | ' | ||||||
14. Earnings Per Share and Equity (Exelon) | |||||||
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 March 31, | |||||||
2014 | 2013 | ||||||
Net income (loss) attributable to common shareholders | $ | 90 | $ | -4 | |||
Weighted average common shares outstanding - basic | 858 | 855 | |||||
Assumed exercise and/or distributions of stock based awards | 3 | 0 | |||||
Weighted average common shares outstanding - diluted | 861 | 855 | |||||
The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 18 million for the three months ended March 31, 2014. For the three months ended March 31, 2013 in which there was a net loss attributable to common shareholders, no potentially dilutive securities are included in the calculation of diluted loss per share, as inclusion of these securities would have reduced the net loss per share. | |||||||
Under share repurchase programs, 35 million shares of common stock are held as treasury stock with a cost of $2.3 billion as of March 31, 2014. In 2008, Exelon management decided to defer indefinitely any share repurchases. |
Commitments_and_Contingencies_
Commitments and Contingencies (Exelon, Generation, ComEd, PECO and BGE) | 3 Months Ended | |||||||||||||||||||||||||
Mar. 31, 2014 | ||||||||||||||||||||||||||
Commitments And Contingencies Tables Disclosure [Line Items] | ' | |||||||||||||||||||||||||
Commitments and Contingencies (Exelon, Generation, ComEd, PECO and BGE) | ' | |||||||||||||||||||||||||
15. 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 22 of the Exelon 2013 Form 10-K. | ||||||||||||||||||||||||||
Commitments | ||||||||||||||||||||||||||
Energy Commitments | ||||||||||||||||||||||||||
As of March 31, 2014, Generation's commitments relating to its purchases from unaffiliated utilities and others of energy, capacity, transmission rights and RECs, are as indicated in the following table: | ||||||||||||||||||||||||||
Net Capacity | REC | Transmission Rights | Purchased Energy | |||||||||||||||||||||||
Purchases (a) | Purchases (b) | Purchases (c) | from CENG | Total | ||||||||||||||||||||||
2014 | $ | 314 | $ | 100 | $ | 19 | $ | 640 | $ | 1,073 | ||||||||||||||||
2015 | 367 | 141 | 13 | 0 | 521 | |||||||||||||||||||||
2016 | 284 | 96 | 2 | 0 | 382 | |||||||||||||||||||||
2017 | 223 | 42 | 2 | 0 | 267 | |||||||||||||||||||||
2018 | 112 | 8 | 2 | 0 | 122 | |||||||||||||||||||||
Thereafter | 414 | 4 | 32 | 0 | 450 | |||||||||||||||||||||
Total | $ | 1,714 | $ | 391 | $ | 70 | $ | 640 | $ | 2,815 | ||||||||||||||||
(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 March 31, 2014, net of fixed capacity payments expected to be received by Generation under contracts to resell such acquired capacity to third parties under long-term capacity sale contracts. Expected payments include certain fixed capacity charges which may be reduced based on plant availability. | ||||||||||||||||||||||||||
(b) The table excludes renewable energy purchases that are contingent in nature. | ||||||||||||||||||||||||||
(c) Transmission rights purchases include estimated commitments for additional transmission rights that will be required to fulfill firm sales contracts. | ||||||||||||||||||||||||||
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 5 — 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 applicable, as of March 31, 2014 are as follows: | ||||||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||||
2019 | ||||||||||||||||||||||||||
Total | 2014 | 2015 | 2016 | 2017 | 2018 | and beyond | ||||||||||||||||||||
ComEd | ||||||||||||||||||||||||||
Electric supply procurement (a) | $ | 591 | $ | 178 | $ | 136 | $ | 137 | $ | 140 | $ | 0 | $ | 0 | ||||||||||||
Renewable energy and RECs (b) | 1,565 | 50 | 72 | 76 | 77 | 83 | 1,207 | |||||||||||||||||||
PECO | ||||||||||||||||||||||||||
Electric supply procurement (c) | 713 | 546 | 167 | 0 | 0 | 0 | 0 | |||||||||||||||||||
AECs (d) | 14 | 2 | 2 | 2 | 2 | 2 | 4 | |||||||||||||||||||
BGE | ||||||||||||||||||||||||||
Electric supply procurement (e) | 1,026 | 541 | 409 | 76 | 0 | 0 | 0 | |||||||||||||||||||
Curtailment services (f) | 120 | 33 | 40 | 34 | 13 | 0 | 0 | |||||||||||||||||||
(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. | ||||||||||||||||||||||||||
(b) ComEd entered into 20-year contracts for renewable energy and RECs beginning in June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. The commitments represent the maximum settlements with suppliers for renewable energy and RECs under the existing contract terms. Pursuant to the ICC's Order on December 19, 2012, ComEd's commitments under the existing long-term contracts were reduced for the June 2013 through May 2014 procurement period. In addition, the ICC's December 18, 2013 order approved the reduction of ComEd's commitments under those contracts for the June 2014 through May 2015 procurement period, and the amount of the reduction was approved by the ICC in March 2014. | ||||||||||||||||||||||||||
(c) PECO entered into various contracts for the procurement of electric supply to serve its default service customers that expire between 2014 and 2016. PECO is permitted to recover its electric supply procurement costs from default service customers with no mark-up in accordance with its PAPUC-approved DSP Programs. See Note 4 - Regulatory Matters for additional information. | ||||||||||||||||||||||||||
(d) PECO is subject to requirements related to the use of alternative energy resources established by the AEPS Act. See Note 4 - Regulatory Matters for additional information. | ||||||||||||||||||||||||||
(e) BGE entered into various contracts for the procurement of electricity that expire between 2014 through 2016. The cost of power under these contracts is recoverable under MDPSC approved fuel clauses. See Note 4 - Regulatory Matters for additional information. | ||||||||||||||||||||||||||
(f) BGE has entered into various contracts with curtailment services providers related to transactions in PJM's capacity market. See Note 4 - Regulatory Matters for additional information. | ||||||||||||||||||||||||||
Fuel Purchase Obligations | ||||||||||||||||||||||||||
In addition to the energy commitments described above, Generation has commitments to purchase fuel supplies for nuclear and fossil generation. PECO and BGE have commitments to purchase natural gas related to transportation, storage capacity and services to serve customers in their gas distribution service territory. As of March 31, 2014, these net commitments were as follows: | ||||||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||||
2019 | ||||||||||||||||||||||||||
Total | 2014 | 2015 | 2016 | 2017 | 2018 | and beyond | ||||||||||||||||||||
Generation | $ | 8,402 | $ | 1,036 | $ | 1,285 | $ | 1,039 | $ | 1,041 | $ | 780 | $ | 3,221 | ||||||||||||
PECO | 479 | 146 | 117 | 98 | 37 | 15 | 66 | |||||||||||||||||||
BGE | 640 | 105 | 82 | 80 | 63 | 52 | 258 | |||||||||||||||||||
Other Purchase Obligations | ||||||||||||||||||||||||||
The Registrants' other purchase obligations as of March 31, 2014, which primarily represent commitments for services, materials and information technology, are as follows: | ||||||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||||
2019 | ||||||||||||||||||||||||||
Total | 2014 | 2015 | 2016 | 2017 | 2018 | and beyond | ||||||||||||||||||||
Exelon | $ | 547 | $ | 150 | $ | 146 | $ | 58 | $ | 49 | $ | 36 | $ | 108 | ||||||||||||
Generation | 462 | 120 | 138 | 45 | 41 | 30 | 88 | |||||||||||||||||||
ComEd (a) | 45 | 11 | 5 | 5 | 5 | 5 | 14 | |||||||||||||||||||
PECO (a) | 28 | 16 | 1 | 3 | 1 | 1 | 6 | |||||||||||||||||||
BGE (a) | 10 | 1 | 2 | 5 | 2 | 0 | 0 | |||||||||||||||||||
____________________ | ||||||||||||||||||||||||||
(a) Purchase obligations include commitments related to smart meter installation. See Note 4 – Regulatory Matters for additional information. | ||||||||||||||||||||||||||
Construction Commitments | ||||||||||||||||||||||||||
Generation has committed to the construction of the Antelope Valley solar PV facility in Los Angeles County, California. The first portion of the project began operations in December 2012, with six additional blocks coming online in 2013 and an expectation of full commercial operation in the first half of 2014. Generation's estimated remaining commitment for the project is $90 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 $47 million and achievement of commercial operations is expected in the fourth quarter of 2014. | ||||||||||||||||||||||||||
On July 26, 2013, Generation executed an engineering procurement and construction contract to expand its Perryman, Maryland generation site with 120 MW of new natural gas-fired generation to satisfy certain merger commitments. The estimated remaining commitment under the contract is $80 million and achievement of commercial operation is expected in 2015. See Note 4 – Mergers and Acquisitions of the Exelon 2013 Form 10-K for additional information on commitments to develop or assist in development of new generation in Maryland resulting from the merger. | ||||||||||||||||||||||||||
On December 27, 2013, Generation executed a Turbine Supply Agreement for construction of the 40 MW Fourmile Wind project in western Maryland. The estimated remaining commitment under the contract is $27 million and achievement of commercial operations is expected in the fourth quarter 2014. In the first quarter of 2014, Generation approved expansion of the Fourmile project to 40MW. This project will satisfy a portion of Exelon's 125 MW Tier I land-based renewables commitment in Maryland. See Note 4 – Mergers and Acquisitions of the Exelon 2013 Form 10-K 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 2013 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 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 commitment also includes $600 million to $650 million relating to Exelon and Generation's development or assistance in the development of 285—300 MWs of new generation in Maryland, which is expected to be completed over a period of 10 years. The MDPSC Order contemplates various options for complying with the new generation development commitments, including building or acquiring generating assets, making subsidy or compliance payments, or in circumstances in which the generation build is delayed, making liquidated damages payments. Exelon and Generation expect that the majority of these commitments will be satisfied by building or acquiring generating assets and, therefore, will be primarily capital in nature and recognized as incurred. If in the future Exelon determines that it is probable that it will make subsidy, compliance or liquidated damages payments related to the new generation development commitments, Exelon will record a liability at that time. As of March 31, 2014, 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. | ||||||||||||||||||||||||||
Contingencies | ||||||||||||||||||||||||||
Commercial Commitments | ||||||||||||||||||||||||||
The Registrants' commercial commitments as of March 31, 2014, representing commitments potentially triggered by future events were as follows: | ||||||||||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||||||||
Letters of credit (non-debt) (a) | $ | 1,717 | $ | 1,675 | $ | 17 | $ | 22 | $ | 1 | ||||||||||||||||
Guarantees | 4,644 | (b) | 1,287 | (c) | 205 | (d) | 181 | (e) | 259 | (f) | ||||||||||||||||
Nuclear insurance premiums (g) | 3,529 | 3,529 | 0 | 0 | 0 | |||||||||||||||||||||
Total commercial commitments | $ | 9,890 | $ | 6,491 | $ | 222 | $ | 203 | $ | 260 | ||||||||||||||||
(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 $0.5 billion at March 31, 2014, which represents the total amount Exelon could be required to fund based on March 31, 2014 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 $0.3 billion at March 31, 2014, which represents the total amount Generation could be required to fund based on March 31, 2014 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) | ||||||||||||||||||||||||||
Generation is subject to liability, property damage and other risks associated with major incidents at any of its nuclear stations, including the CENG nuclear stations. Generation has reduced its financial exposure to these risks through insurance and other industry risk-sharing provisions | ||||||||||||||||||||||||||
The Price-Anderson Act was enacted to ensure the availability of funds for public liability claims arising from an incident at any of the U.S. licensed nuclear facilities and also to limit the liability of nuclear reactor owners for such claims from any single incident. As of March 31, 2014, the current liability limit per incident was $13.6 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. An inflation adjustment must be made at least once every 5 years and the last inflation adjustment was made effective September 10, 2013. In accordance with the Price-Anderson Act, Generation maintains financial protection at levels equal to the amount of liability insurance available from private sources through the purchase of private nuclear energy liability insurance for public liability claims that could arise in the event of an incident. As of March 31, 2014, the amount of nuclear energy liability insurance purchased is $375 million for each operating site. Additionally, the Price-Anderson Act requires a second layer of protection through the mandatory participation in a retrospective rating plan for power reactors (currently 104 reactors) resulting in an additional $13.2 billion in funds available for public liability claims. Participation in this secondary financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident that exceeds the primary layer of financial protection. Under the Price-Anderson Act, the maximum assessment in the event of an incident for each nuclear operator, per reactor, per incident (including a 5% surcharge), is $127.3 million, payable at no more than $19 million per reactor per incident per year. Exelon's maximum liability per incident is approximately $2.4 billion. | ||||||||||||||||||||||||||
In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $13.6 billion limit for a single incident. | ||||||||||||||||||||||||||
Generation is 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 $3.5 billion, which is included above in the Commercial Commitments table. See the Nuclear Insurance section within Note 22 – Commitments and Contingencies of the Exelon 2013 Form 10-K for additional details on Generation's nuclear insurance premiums. | ||||||||||||||||||||||||||
Spent Nuclear Fuel Obligation (Exelon and Generation) | ||||||||||||||||||||||||||
Under the NWPA, the DOE is responsible for the development of a geologic repository for and the disposal of SNF and high-level radioactive waste. As required by the NWPA, Generation is a party to contracts with the DOE (Standard Contracts) to provide for disposal of SNF from Generation's nuclear generating stations. In accordance with the NWPA and the Standard Contracts, Generation pays the DOE one mill ($0.001) per kWh of net nuclear generation for the cost of SNF disposal. This fee may be adjusted prospectively in order to ensure full cost recovery. The NWPA and the Standard Contracts required the DOE to begin taking possession of SNF generated by nuclear generating units by no later than January 31, 1998. The DOE, however, failed to meet that deadline and its performance will be delayed significantly. On November 19, 2013, the D.C. Circuit Court ordered the DOE to submit to Congress a proposal to reduce the current SNF disposal fee to zero, unless and until there is a viable disposal program. On January 3, 2014, the DOE filed a petition for rehearing which was denied by the D.C. Circuit Court on March 18, 2014. Also, on January 3, 2014, the DOE submitted a proposal to Congress to reduce the current SNF disposal fee to zero, subject to any further action on its request for rehearing. For the year ended December 31, 2013, Generation incurred expense of $136 million in SNF disposal fees, recorded in Purchased power and fuel expense within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income, including Exelon's share of Salem and net of co-owner reimbursements (not including such fees incurred by CENG). The DOE's submitted proposal becomes effective after 90-days of continuous Congressional session, unless there is Congressional action contrary to the DOE proposal. Until such time as a new fee structure is in effect, Generation must continue to pay the current SNF disposal fees. | ||||||||||||||||||||||||||
Indemnifications Related to Sale of Sithe (Exelon and Generation) | ||||||||||||||||||||||||||
On January 31, 2005, subsidiaries of Generation completed a series of transactions that resulted in Generation's sale of its investment in Sithe. Specifically, subsidiaries of Generation consummated the acquisition of Reservoir Capital Group's 50% interest in Sithe and subsequently sold 100% of Sithe to Dynegy, Inc. (Dynegy). | ||||||||||||||||||||||||||
The estimated maximum possible exposure to Exelon related to the guarantees provided as part of the sales transaction to Dynegy was approximately $200 million at December 31, 2013. The guarantee expired January 31, 2014. Generation was not required to make payments under the guarantee, and, therefore, has no further obligation related to this guarantee as of March 31, 2014. | ||||||||||||||||||||||||||
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 2017. | ||||||||||||||||||||||||||
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. See Note 4 - Regulatory Matters for additional information regarding the associated regulatory assets. | ||||||||||||||||||||||||||
As of March 31, 2014 and December 31, 2013, 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: | ||||||||||||||||||||||||||
31-Mar-14 | Total Environmental Investigation and Remediation Reserve | Portion of Total Related to MGP Investigation and Remediation | ||||||||||||||||||||||||
Exelon | $ | 332 | $ | 267 | ||||||||||||||||||||||
Generation | 56 | 0 | ||||||||||||||||||||||||
ComEd | 230 | 225 | ||||||||||||||||||||||||
PECO | 45 | 42 | ||||||||||||||||||||||||
BGE | 1 | 0 | ||||||||||||||||||||||||
31-Dec-13 | Total Environmental Investigation and Remediation Reserve | Portion of Total Related to MGP Investigation and Remediation | ||||||||||||||||||||||||
Exelon | $ | 338 | $ | 273 | ||||||||||||||||||||||
Generation | 56 | 0 | ||||||||||||||||||||||||
ComEd | 234 | 229 | ||||||||||||||||||||||||
PECO | 47 | 44 | ||||||||||||||||||||||||
BGE | 1 | 0 | ||||||||||||||||||||||||
The Registrants cannot reasonably estimate whether they will incur other significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies or others, or whether such costs will be recoverable from third parties, including customers. | ||||||||||||||||||||||||||
Water Quality | ||||||||||||||||||||||||||
Section 316(b) of the Clean Water Act. Section 316(b) requires that the cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts, and is implemented through state-level NPDES permit programs. All of Generation's and CENG's power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems (e.g., cooling towers) are potentially most affected by changes to the existing regulations. For Generation, those facilities are Clinton, Dresden, Eddystone, Fairless Hills, Gould Street, Handley, Mountain Creek, Mystic 7, Oyster Creek, Peach Bottom, Quad Cities, Riverside, Salem and Schuylkill. For CENG, those facilities are Calvert Cliffs, Nine Mile Point Unit 1 and R.E. Ginna. | ||||||||||||||||||||||||||
On March 28, 2011, the U.S. EPA issued the proposed regulation under Section 316(b). The proposal does not require closed-cycle cooling (e.g., cooling towers) as the best technology available to address impingement and entrainment. The proposal provides the state permitting agency with discretion to determine the best technology available to limit entrainment (drawing aquatic life into the plants cooling system) mortality, including application of a cost-benefit test and the consideration of a number of site-specific factors. After consideration of these factors, the state permitting agency may require closed cycle cooling, an alternate technology, or determine that the current technology is the best available. The proposed rule also imposes limits on impingement (trapping aquatic life on screens) mortality, which likely will be accomplished by the installation of screens or another technology at the intake. Exelon filed comments on the proposed regulation on August 18, 2011, stating its support for a number of its provisions (e.g., cooling towers not required as best technology available, and the use of site-specific and cost benefit analysis) while also noting a number of technical provisions that require revision to take into account existing unit operations and practices within the industry. | ||||||||||||||||||||||||||
In June 2012, the U.S. EPA published two Notices of Data Availability (NODA) seeking public comment on alternate compliance technologies for impingement and the use of a public opinion survey to calculate the so-called “non-use” benefits of the rule. Exelon filed comments for each NODA, supporting the additional flexibility afforded by the impingement NODA, and opposing the NODA relating to calculation of non-use benefits due to its inaccurate and unreliable methodologies that would artificially inflate the benefits of proposed technologies that would otherwise not be cost-effective. On June 27, 2013, the U.S. EPA agreed to amend the court approved Settlement Agreement to extend the deadline to issue a final rule until November 4, 2013 and on October 30, 2013 the U.S. EPA invoked the force majeure provision of the Settlement Agreement to extend the final rule deadline until January 14, 2014 due to the early October 2013 federal government shutdown. The parties then agreed to an additional extension until April 17, 2014. The U.S. EPA has announced that it will not meet this latest deadline and has established May 16, 2014 as the date for issuance of the final rule. Until the rule is finalized, the state permitting agencies will continue to apply their best professional judgment to address impingement and entrainment. | ||||||||||||||||||||||||||
Salem and Other Power Generation Facilities. In June 2001, the NJDEP issued a renewed NPDES permit for Salem, allowing for the continued operation of Salem with its existing cooling water system. NJDEP advised PSEG, in July 2004 that it strongly recommended reducing cooling water intake flow commensurate with closed-cycle cooling as a compliance option for Salem. PSEG submitted an application for a renewal of the permit on February 1, 2006. In the permit renewal application, PSEG analyzed closed-cycle cooling and other options and demonstrated that the continuation of the Estuary Enhancement Program, an extensive environmental restoration program at Salem, is the best technology to meet the Section 316(b) requirements. PSEG continues to operate Salem under the approved June 2001 NPDES permit while the NPDES permit renewal application is being reviewed. If the final permit or Section 316(b) regulations ultimately requires the retrofitting of Salem's cooling water intake structure to reduce cooling water intake flow commensurate with closed-cycle cooling, Exelon's and Generation's share of the total cost of the retrofit and any resulting interim replacement power would likely be in excess of $430 million, based on a 2006 estimate, and would result in increased depreciation expense related to the retrofit investment. | ||||||||||||||||||||||||||
It is unknown at this time whether the NJDEP permit programs will require closed-cycle cooling at Salem. In addition, the economic viability of Generation's other power generation facilities, as well as CENG's, without closed-cycle cooling water systems will be called into question by any requirement to construct cooling towers. Should the final rule not require the installation of cooling towers, and retain the flexibility afforded the state permitting agencies in applying a cost benefit test and to consider site-specific factors, the impact of the rule would be minimized even though the costs of compliance could be material to Generation and CENG. | ||||||||||||||||||||||||||
Given the uncertainties associated with the requirements that will be contained in the final rule, Generation cannot predict the eventual outcome or estimate the effect that compliance with any resulting Section 316(b) or interim state requirements will have on the operation of its and CENG's generating facilities and its future results of operations, cash flows and financial position. | ||||||||||||||||||||||||||
Groundwater Contamination. In October 2007, a subsidiary of Constellation entered into a consent decree with the MDE relating to groundwater contamination at a third-party facility that was licensed to accept fly ash, a byproduct generated by coal-fired plants. The consent decree required the payment of a $1 million penalty, remediation of groundwater contamination resulting from the ash placement operations at the site, replacement of drinking water supplies in the vicinity of the site, and monitoring of groundwater conditions. Prior to the Merger, Constellation recorded in its Consolidated Balance Sheets total liabilities of approximately $30 million to comply with the consent decree with an additional $3 million recognized through purchase accounting. During third quarter of 2013, Generation increased its reserve by $2 million based on an update of future estimated remediation costs. The remaining liability as of March 31, 2014, is approximately $15 million. In addition, a private party asserted claims relating to groundwater contamination. In February 2014, Generation settled these private party claims for an amount that is not material to the financial condition of Generation. | ||||||||||||||||||||||||||
Air Quality | ||||||||||||||||||||||||||
Cross State Air Pollution Rule (CSAPR). On July 11, 2008, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) vacated the CAIR, which had been promulgated by the U.S. EPA to reduce power plant emissions of SO2 and NOx. The D.C. Circuit Court later remanded the CAIR to the U.S. EPA, without invalidating the entire rulemaking, so that the U.S. EPA could correct CAIR in accordance with the D.C. Circuit Court's July 11, 2008 opinion. On July 7, 2011, the U.S. EPA published the final rule, known as the CSAPR. The CSAPR requires 28 states in the eastern half of the United States to significantly improve air quality by reducing power plant emissions that cross state lines and contribute to ground-level ozone and fine particle pollution in other states. | ||||||||||||||||||||||||||
Numerous entities challenged the CSAPR in the D.C. Circuit Court, and some requested a stay of the rule pending the Court's consideration of the matter on the merits. On December 30, 2011, the Court granted a stay of the CSAPR, and directed the U.S. EPA to continue the administration of CAIR in the interim. On August 21, 2012, a three-judge panel of the D.C. Circuit Court held that the U.S. EPA has exceeded its authority in certain material aspects of the CSAPR and vacated the rule and remanded it to the U.S. EPA for further rulemaking consistent with its decision. The Court also ordered that CAIR remain in effect pending finalization of CSAPR on remand. The Court's order was appealed to the U.S. Supreme Court, and on April 29, 2014, the U.S. Supreme Court reversed the Appellate Court decision and upheld CSAPR, and remanded the case to the Appellate Court to resolve the remaining implementation issues. | ||||||||||||||||||||||||||
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 March 31, 2014, Generation had $51 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 challenged MATS in the D.C. Circuit Court, and Exelon intervened in support of the rule. On April 15, 2014, the D.C Circuit Court issued an opinion upholding MATS in its entirety. | ||||||||||||||||||||||||||
Exelon, along with the other co-owners of Conemaugh Generating Station have improved the existing scrubbers and installed Selective Catalytic Reduction (SCR) controls to meet the requirements of MATS. | ||||||||||||||||||||||||||
In addition, as of March 31, 2014, Exelon had a $368 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 8 – Impairment of Long-Lived Assets of the Exelon 2013 Form 10-K 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. U.S. EPA will require states to submit state implementation plans (SIPs) for nonattainment areas by April 2015. With regard to Texas and Maryland, no nonattainment areas were identified in EPA's final designation rule. With regard to Illinois and Pennsylvania, several counties, or portions of counties, in each state were identified as nonattainment. The U.S. EPA will follow the approach outlined in a February 2013 U.S. EPA strategy document that establishes a process and timeline for the Agency to address additional designations in states' counties under a future rulemaking. Nonattainment county compliance with the one-hour SO2 standard is required by October 2018. While significant SO2 reductions will occur as a result of MATS compliance in 2015, Exelon is unable to predict the requirements of pending states' SIPs to further reduce SO2 emissions in support of attainment of the one hour SO2 standard. | ||||||||||||||||||||||||||
Notices and Finding of Violations and Midwest Generation Bankruptcy. In December 1999, ComEd sold several generating stations to Midwest Generation, LLC (Midwest Generation), a subsidiary of Edison Mission Energy (EME). Under the terms of the sale agreement, Midwest Generation and EME assumed responsibility for environmental liabilities associated with the ownership, occupancy, use and operation of the stations, including responsibility for compliance by the stations with environmental laws before their purchase by Midwest Generation. Midwest Generation and EME additionally agreed to indemnify and hold ComEd and its affiliates harmless from claims, fines, penalties, liabilities and expenses arising from third party claims against ComEd resulting from or arising out of the environmental liabilities assumed by Midwest Generation and EME under the terms of the agreement governing the sale. In connection with Exelon's 2001 corporate restructuring, Generation assumed ComEd's rights and obligations with respect to its former generation business, including its rights and obligations under the sale agreement with Midwest Generation and EME. | ||||||||||||||||||||||||||
Under a supplemental agreement reached in 2003, Midwest Generation agreed to reimburse ComEd and Generation for 50% of the specific asbestos claims pending as of February 2003 and related expenses less recovery of insurance costs and agreed to a sharing arrangement for liabilities and expenses associated with future asbestos-related claims as specified in the agreement. | ||||||||||||||||||||||||||
On December 17, 2012 (Petition Date), EME and certain of its subsidiaries, including Midwest Generation, filed for protection under Chapter 11 of the U.S. Bankruptcy Code. | ||||||||||||||||||||||||||
In 2012, the Bankruptcy Court approved the rejection of an agency agreement related to a coal rail car lease under which Midwest Generation had agreed to reimburse ComEd for all obligations incurred under the coal rail car lease. The rejection left Generation as the party responsible for making all remaining payments under the lease and performing all other obligations there under. In January 2013, Generation made the final $10 million payment due under the lease agreement which had been accrued at December 31, 2012. | ||||||||||||||||||||||||||
During the second quarter of 2013, Exelon filed proofs of claim for approximately $21 million with the Bankruptcy Court for amounts owed by EME and Midwest Generation for the coal rail car lease, ComEd utility payments and certain legal costs. Further, Exelon filed an environmental claim with an unspecified amount that listed the indemnifications that were in place pre-Petition Date and other factors associated with the remediation and a claim under the asbestos cost-sharing agreement with an unspecified amount. As of March 31, 2014, Exelon has not recorded a receivable for the filed proofs of claim because recovery of any amount cannot be assured at this point in the bankruptcy. Exelon will not record claim recoveries unless and until they are realized. | ||||||||||||||||||||||||||
On January 17, 2014, Midwest Generation filed a plan supplement to its bankruptcy filing that included a list of contracts to be rejected upon the effective date of the reorganization plan. This list included the sale agreement, including the environmental indemnity, and the asbestos cost-sharing agreement. | ||||||||||||||||||||||||||
On March 11, 2014, the Bankruptcy Court for the Northern District of Illinois entered its Order Confirming Debtors' Joint Chapter 11 Plan of Reorganization. On April 1, 2014 (Effective Date), NRG Energy purchased EME's portfolio of generation, including Midwest Generation and the Joint Chapter 11 Plan of Reorganization (Plan) became effective. As part of the Plan, the sale agreement, including the environmental indemnity, and the asbestos cost-sharing agreement were rejected. Creditors have 30 days from the Effective Date to file rejection damages claims associated with contracts rejected under the Plan. Exelon will be filing claims related to the rejected agreements. | ||||||||||||||||||||||||||
Certain environmental laws and regulations subject current and prior owners of properties or generators of hazardous substances at such properties to liability for remediation costs of environmental contamination. As a prior owner of the generating stations, ComEd (and Generation, through its agreement in Exelon's 2001 corporate restructuring to assume ComEd's rights and obligations associated with its former generation business) could face liability (along with any other potentially responsible parties) for environmental conditions at the stations requiring remediation, with the determination of the allocation among the parties subject to many uncertain factors. ComEd and Generation have reviewed available public information as to potential environmental exposures regarding the Midwest Generation station sites. Midwest Generation publicly disclosed in its December 31, 2013 Form 10-K 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 two Midwest Generation plant sites, (ii) it has identified stations for which a reasonable estimate for investigation and/ or remediation cannot be made and (iii) it and the Illinois EPA entered into Compliance Commitment Agreements outlining specified environmental remediation measures and groundwater monitoring activities to be undertaken at its Crawford, Powerton, Joliet, Will County and Waukegan generating stations. At this time, however, ComEd and Generation do not have sufficient information to reasonably assess the potential likelihood or magnitude of any remediation requirements that may be asserted. For these reasons, ComEd and Generation are unable to predict whether and to what extent they may ultimately be held responsible for remediation and other costs relating to the generating stations and as a result no liability has been recorded as of March 31, 2014. Any liability imposed on ComEd or Generation for environmental matters relating to the generating stations could have a material adverse impact on their future results of operations and cash flows. | ||||||||||||||||||||||||||
Generation increased its reserve for asbestos-related bodily injury claims at December 31, 2013 by $25 million, as a result of Midwest Generation listing such agreement in the January 2014 plan supplement as an agreement to be rejected in connection with the Plan. As discussed above, the rejection became effective as part of the Plan and no further adjustment to the reserve is required. Midwest Generation publicly disclosed in its December 31, 2013 Form 10-K that they had $53 million recorded related to asbestos bodily injury claims under the contractual indemnity with ComEd. Exelon and Generation may be entitled to damages associated with the rejection of the agreement. These amounts are considered to be contingent gains and would not be recognized until realized. | ||||||||||||||||||||||||||
Solid and Hazardous Waste | ||||||||||||||||||||||||||
Cotter Corporation. The U.S. EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. On February 18, 2000, ComEd sold Cotter to an unaffiliated third party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising in connection with the West Lake Landfill. In connection with Exelon's 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. On May 29, 2008, the U.S. EPA issued a Record of Decision approving the remediation option submitted by Cotter and the two other PRPs that required additional landfill cover. 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, and subsequently requested additional analysis sampling and modeling that will be conducted throughout 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 Generation's preliminary review, it appears probable that Generation has liability to Cotter under the indemnification agreement and has established an appropriate accrual for this liability. | ||||||||||||||||||||||||||
On February 28, 2012, and April 12, 2012, two lawsuits were filed in the U.S. District Court for the Eastern District of Missouri against 15 and 14 defendants, respectively, including Exelon, Generation and ComEd (the “Exelon defendants”) and Cotter. The suits allege that individuals living in the North St. Louis area developed some form of cancer due to the defendants' negligent or reckless conduct in processing, transporting, storing, handling and/or disposing of radioactive materials. Plaintiffs have asserted claims for negligence, strict liability, emotional distress, medical monitoring, and violations of the Price-Anderson Act. The complaints do not contain specific damage claims. On May 30, 2012, the plaintiffs filed voluntary motions to dismiss the Exelon defendants from both lawsuits which were subsequently granted. Since May 30, 2012, several related lawsuits have been filed in the same court on behalf of various plaintiffs against Cotter and other defendants, but not Exelon. The allegations in these related lawsuits mirror the initially filed lawsuits. In the event of a finding of liability, it is reasonably possible that Exelon would be considered liable due to its indemnification responsibilities of Cotter described above. On March 27, 2013, the U.S. District Court dismissed all state common law actions brought under the initial two lawsuits; and also found that the plaintiffs had not properly brought the actions under the Price-Anderson Act. On July 8, 2013, the plaintiffs filed amended complaints under the Price-Anderson Act. Cotter moved to dismiss the amended complaints and has motions currently pending before the court. At this stage of the litigation, Exelon cannot estimate a range of loss, if any. | ||||||||||||||||||||||||||
On April 11, 2014, a class action complaint was filed in the U.S. District Court for the Eastern District of Missouri against Cotter and six additional defendants. The complaint alleges that individuals living in the North St. Louis area within a three-mile radius of the West Lake Landfill suffered damage to property or loss of use of property due to the defendants' negligent handling of radioactive materials. Plaintiffs have asserted claims for monetary damages under the Price-Anderson Act. At this stage of the litigation, Exelon and Generation 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 PRP's submitted their investigation of the range of clean-up options in the first quarter of 2011. Although the investigation and options provided to the U.S. EPA are still subject to U.S. EPA review and selection of a remedy, the range of estimated clean-up costs to be allocated among all of the PRPs is in the range of $50 million to $64 million. On September 30, 2013, U.S. EPA issued the Record of Decision identifying its preferred remedial alternative for the site. The estimated cost for the alternative chosen by U.S. EPA is consistent with the PRPs estimated range of costs noted above. Based on Generation's preliminary review, it appears probable that Generation has liability and has established an appropriate accrual for its share of the estimated clean-up costs. A wholly owned subsidiary of Generation has agreed to indemnify BGE for most of the costs related to this settlement and clean-up of the site. | ||||||||||||||||||||||||||
Rossville Ash Site. The Rossville Ash Site is a 32-acre property located in Rosedale, Baltimore County, Maryland, which was used for the placement of fly ash from 1983-2007. The property is owned by Constellation Power Source Generation, LLC (CPSG). In 2008, CPSG investigated and remediated the property by entering it into the Maryland Voluntary Cleanup Program (VCP) to address any historic environmental concerns and ready the site for appropriate future redevelopment. The site was accepted into the program in 2010 and is currently going through the process to remediate the site and receive closure from MDE. Exelon currently estimates the cost to close the site to be approximately $6 million, which has been fully reserved as of March 31, 2014. | ||||||||||||||||||||||||||
Sauer Dump. On May 30, 2012, BGE was notified by the U.S. EPA that it is considered a PRP at the Sauer Dump Superfund site in Dundalk, Maryland. The U.S. EPA offered BGE and three other PRPs the opportunity to conduct an environmental investigation and present cleanup recommendations at the site. In addition, the U.S. EPA is seeking recovery from the PRPs of $1.7 million for past cleanup and investigation costs at the site. On March 11, 2013, BGE and three other PRP's signed an Administrative Settlement Agreement and Order on Consent with the U.S. EPA which requires the PRP's to conduct a Remedial Investigation and Feasibility Study at the site to determine what, if any, are the appropriate and recommended cleanup activities for the site. The ultimate outcome of this proceeding is uncertain. Since the U.S. EPA has not selected a cleanup remedy and the allocation of the cleanup costs among the PRPs has not been determined, an estimate of the range of BGE's reasonably possible loss, if any, cannot be determined. | ||||||||||||||||||||||||||
Climate Change Regulation. Exelon is subject to climate change regulation or legislation at the Federal, regional and state levels. In 2007, the U.S. Supreme Court ruled that GHG emissions are pollutants subject to regulation under the new motor vehicle provisions of the Clean Air Act. Consequently, on December 7, 2009, the U.S. EPA issued an endangerment finding under Section 202 of the Clean Air Act regarding GHGs from new motor vehicles and on April 1, 2010 issued final regulations limiting GHG emissions from cars and light trucks effective on January 2, 2011. While such regulations do not specifically address stationary sources, such as a generating plant, it is the U.S. EPA's position that the regulation of GHGs under the mobile source provisions of the Clean Air Act has triggered the permitting requirements under the Prevention of Significant Deterioration (PSD) and Title V operating permit sections of the Clean Air Act for new and modified stationary sources effective January 2, 2011. Therefore, on May 13, 2010, the U.S. EPA issued final regulations (the Tailoring Rule) relating to these provisions of the Clean Air Act for major stationary sources of GHG emissions that apply to new sources that emit greater than 100,000 tons per year, on a CO2 equivalent basis, and to modifications to existing sources that result in emissions increases greater than 75,000 tons per year on a CO2 equivalent basis. These thresholds became effective January 2, 2011, apply for six years and will be reviewed by the U.S. EPA for future applicability thereafter. On July 2, 2012 the U.S. EPA declined to lower GHG permit thresholds in its final “Step 3” Tailoring Rule update. The U.S. EPA will review permit thresholds again in a 2015 rulemaking process. On June 26, 2012, the United States Court of Appeals for the District of Columbia, in a per curium decision, dismissed industry and state petitions challenging the U.S. EPA's “Tailpipe Rule” for cars and light duty trucks, the endangerment finding for GHG's from stationary sources, and the Tailoring Rule. On October 15, 2013, the U.S. Supreme Court granted industry petitions to review one aspect of the PSD permitting regulations. Under the PSD regulations, new and modified major stationary sources could be required to install best available control technology, to be determined on a case by case basis. Generation could be significantly affected by the regulations if it were to build new plants or modify existing plants. | ||||||||||||||||||||||||||
On June 25, 2013, President Obama announced “The President's Climate Action Plan,” a summary of executive branch actions intended to: reduce carbon emissions; prepare the United States for the impacts of climate change; and lead international efforts to combat global climate change and prepare for its impacts. Concurrent with the announcement of the Administration's plan, the President also issued a Memorandum for the Administrator of the Environmental Protection Agency that focused on power generation sector carbon reductions under the Section 111 New Source Performance Standards (NSPS) section of the federal Clean Air Act. The memorandum directs the U.S. EPA Administrator to issue two sets of proposed rulemakings with regard to power plant carbon emissions under Section 111 of the Clean Air Act. | ||||||||||||||||||||||||||
The first rulemaking, under Section 111(b) of the Clean Air Act is to focus on establishing carbon regulations for new fossil-fuel power plants. This rulemaking was proposed on September 20, 2013 and is to be finalized “in a timely fashion.” In the proposed rule U.S. EPA sets separate standards for fossil-fuel fired utility boilers and natural gas fired stationary combustion turbines. | ||||||||||||||||||||||||||
The second rulemaking, under Section 111(d) of the Clean Air Act is to focus on modified, reconstructed and existing fossil power plants. The rulemaking is to be proposed no later than June 1, 2014, be finalized no later than June 1, 2015, and require that states submit to U.S. EPA their implementation plans no later than June 30, 2016. In developing this rulemaking, U.S. EPA is directed to consider a number of factors, including options to reduce costs, options to ensure the continued use of a range of energy sources and technologies, options that are consistent with reliable and affordable power, and options that allow for the use of market-based instruments, performance standards and other regulatory flexibilities. | ||||||||||||||||||||||||||
To the extent that the final Section 111(d) rule results in emission reductions from fossil fuel fired plants, and thereby imposes some form of direct or indirect price of carbon in competitive electricity markets, Exelon's overall low carbon generation portfolio results could benefit. | ||||||||||||||||||||||||||
Litigation and Regulatory Matters | ||||||||||||||||||||||||||
Except to the extent noted below, the circumstances set forth in Note 22 of the Exelon 2013 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, PECO and BGE) | ||||||||||||||||||||||||||
Exelon and Generation. Generation maintains a reserve for claims associated with asbestos-related personal injury actions in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. The reserve is recorded on an undiscounted basis and excludes the estimated legal costs associated with handling these matters, which could be material. | ||||||||||||||||||||||||||
At March 31, 2014 and December 31, 2013, Generation had reserved approximately $89 million and $90 million, respectively, in total for asbestos-related bodily injury claims. As of March 31, 2014, approximately $20 million of this amount related to 238 open claims presented to Generation, while the remaining $69 million of the reserve is for estimated future asbestos-related bodily injury claims anticipated to arise through 2050, based on actuarial assumptions and analyses, which are updated on an annual basis. On a quarterly basis, Generation monitors actual experience against the number of forecasted claims to be received and expected claim payments and evaluates whether an adjustment to the reserve is necessary. | ||||||||||||||||||||||||||
On November 22, 2013, the Supreme Court of Pennsylvania held that the Pennsylvania Workers Compensation Act does not apply to an employee's disability or death resulting from occupational disease, such as diseases related to asbestos exposure, which manifests more than 300 weeks after the employee's last employment-based exposure, and that therefore the exclusivity provision of the Act does not preclude such employee from suing his or her employer in court. The Supreme Court's ruling reverses previous rulings by the Pennsylvania Superior Court precluding current and former employees from suing their employers in court, despite the fact that the same employee was not eligible for workers compensation benefits for diseases that manifest more than 300 weeks after the employee's last employment-based exposure to asbestos. Currently, Exelon, Generation and PECO are unable to predict whether and to what extent they may experience additional claims in the future as a result of this ruling; as such no increase to the asbestos-related bodily injury liability has been recorded as of March 31, 2014. Increased claims activity resulting from this ruling could have a material adverse effect on Exelon's, Generation's and PECO's future results of operations and cash flows. | ||||||||||||||||||||||||||
BGE. Since 1993, BGE and certain Constellation (now Generation) subsidiaries have been involved in several actions concerning asbestos. The actions are based upon the theory of "premises liability," alleging that BGE and Generation knew of and exposed individuals to an asbestos hazard. In addition to BGE and Generation, numerous other parties are defendants in these cases. | ||||||||||||||||||||||||||
Approximately 486 individuals who were never employees of BGE or certain Constellation subsidiaries have pending claims each seeking several million dollars in compensatory and punitive damages. Cross-claims and third-party claims brought by other defendants may also be filed against BGE and certain Constellation subsidiaries in these actions. To date, most asbestos claims which have been resolved have been dismissed or resolved without any payment by BGE or certain Constellation subsidiaries and a small minority of these cases has been resolved for amounts that were not material to BGE or Generation's financial results. | ||||||||||||||||||||||||||
Discovery begins in these cases after they are placed on the trial docket. At present, only two of the pending cases are set for trial. Given the limited discovery in these cases, BGE and Generation do not know the specific facts that are necessary to provide an estimate of the reasonably possible loss relating to these claims; as such, no accrual has been made and a range of loss is not estimable. The specific facts not known include: | ||||||||||||||||||||||||||
the identity of the facilities at which the plaintiffs allegedly worked as contractors; | ||||||||||||||||||||||||||
the names of the plaintiffs' employers; | ||||||||||||||||||||||||||
the dates on which and the places where the exposure allegedly occurred; and | ||||||||||||||||||||||||||
the facts and circumstances relating to the alleged exposure. | ||||||||||||||||||||||||||
Insurance and hold harmless agreements from contractors who employed the plaintiffs may cover a portion of any awards in the actions. | ||||||||||||||||||||||||||
Continuous Power Interruption (ComEd) | ||||||||||||||||||||||||||
Section 16-125 of the Illinois Public Utilities Act provides that in the event an electric utility, such as ComEd, experiences a continuous power interruption of four hours or more that affects (in ComEd's case) more than 30,000 customers, the utility may be liable for actual damages suffered by customers as a result of the interruption and may be responsible for reimbursement of local governmental emergency and contingency expenses incurred in connection with the interruption. Recovery of consequential damages is barred. The affected utility may seek from the ICC a waiver of these liabilities when the utility can show that the cause of the interruption was unpreventable damage due to weather events or conditions, customer tampering, or certain other causes enumerated in the law. | ||||||||||||||||||||||||||
On August 18, 2011, ComEd sought from the ICC a determination that ComEd is not liable for damage compensation to customers in connection with the July 11, 2011 storm system that produced multiple power interruptions that in the aggregate affected more than 900,000 customers in ComEd's service territory, as well as for five other storm systems that affected ComEd's customers during June and July 2011 (Summer 2011 Storm Docket). In addition, on September 29, 2011, ComEd sought from the ICC a determination that it was not liable for damage compensation related to the February 1, 2011 blizzard (February 2011 Blizzard Docket). | ||||||||||||||||||||||||||
On June 5, 2013, the ICC approved a complete waiver of liability for five of the six summer storms and the February 2011 blizzard. The ICC held that for the July 11, 2011 storm, 34,559 interruptions were preventable and therefore no waiver should apply. As required by the ICC's Order, ComEd notified relevant customers that they may be entitled to seek reimbursement of incurred costs in accordance with a claims procedure established under ICC rules and regulations. In addition, the ICC found that ComEd did not systematically fail in its duty to provide adequate, reliable and safe service. As a result, the ICC rejected the Illinois Attorney General's request for the ICC to open an investigation into ComEd's infrastructure and storm hardening investments. | ||||||||||||||||||||||||||
Following the ICC's June 26, 2013 denial of ComEd's request for rehearing, on June 27, 2013 ComEd filed an appeal of both the summer and winter storm dockets with the Illinois Appellate Court regarding the ICC's interpretation of Section 16-125 of the Illinois Public Utilities Act. ComEd cannot predict the outcome of appeals. | ||||||||||||||||||||||||||
As a result of the ICC's June 5, 2013 ruling, ComEd established a liability, which was not material, for potential reimbursements for actual damages incurred by the 34,559 customers covered by the ICC's June 5, 2013 Order. The liability recorded represents the low end of a range of potential losses given that no amount within the range represents a better estimate. ComEd's ultimate liability will be based on actual claims eligible for reimbursement as well as the outcome of the appeal. Although reimbursements for actual damages will differ from the estimated accrual recorded, at this time ComEd does not expect the difference to be material to ComEd's results of operations or cash flows. | ||||||||||||||||||||||||||
ComEd has not recorded an accrual for reimbursement of local governmental emergency and contingency expenses as a range of loss, if any, cannot be reasonably estimated at this time, but may be material to ComEd's results of operations and cash flows. | ||||||||||||||||||||||||||
Telephone Consumer Protection Act Lawsuit (ComEd) | ||||||||||||||||||||||||||
On November 19, 2013, a class action complaint was filed in the Northern District of Illinois on behalf of a single individual and a presumptive class that would include all customers that ComEd enrolled in its Outage Alert text message program. The complaint alleges that ComEd violated the Telephone Consumer Protection Act (“TCPA”) by sending approximately 1.2 million text messages to customers without first obtaining their consent to receive such messages. The complaint seeks certification of a class along with statutory damages, attorneys' fees, and an order prohibiting ComEd from sending additional text messages. Such statutory damages could range from $ 500 to $ 1,500 per text. On February 21, 2014, ComEd filed a motion to dismiss this class action complaint and intends to contest the allegations of this suit. As of March 31, 2014, ComEd established a reserve, which was not material, representing its best estimate of probable loss associated with this class action complaint. As ComEd is unable to predict the ultimate outcome of this proceeding, actual damages may differ from the estimated amount recorded, which may be material to ComEd's results of operations, cash flows, and financial position. | ||||||||||||||||||||||||||
Baltimore City Franchise Taxes (BGE) | ||||||||||||||||||||||||||
The City of Baltimore claims that BGE has maintained electric facilities in the City's public right-of-ways for over one hundred years without the proper franchise rights from the City. BGE is currently reviewing the merits of this claim. BGE has not recorded an accrual for payment of franchise fees for past periods as a range of loss, if any, cannot be reasonably estimated at this time. Franchise fees assessed in future periods may be material to BGE's results of operations and cash flows. | ||||||||||||||||||||||||||
General (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||||||||||||
The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The Registrants maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. | ||||||||||||||||||||||||||
Income Taxes (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||||||||||||
See Note 9 - 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) | 3 Months Ended | |||||||||||||||||
Mar. 31, 2014 | ||||||||||||||||||
Supplemental Financial Information Tables [Line Items] | ' | |||||||||||||||||
Supplemental Financial Information (Exelon, Generation, ComEd, PECO and BGE) | ' | |||||||||||||||||
16. Supplemental Financial Information (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||||
Supplemental Statement of Operations Information | ||||||||||||||||||
The following tables provide additional information about the Registrants' Consolidated Statements of Operations for the three months ended March 31, 2014 and 2013: | ||||||||||||||||||
Three Months Ended March 31, 2014 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||
Other, Net | ||||||||||||||||||
Decommissioning-related activities: | ||||||||||||||||||
Net realized income on decommissioning trust funds (a) | ||||||||||||||||||
Regulatory agreement units | $ | 43 | $ | 43 | $ | 0 | $ | 0 | $ | 0 | ||||||||
Non-regulatory agreement units | 25 | 25 | 0 | 0 | 0 | |||||||||||||
Net unrealized gains on decommissioning trust funds | ||||||||||||||||||
Regulatory agreement units | 61 | 61 | 0 | 0 | 0 | |||||||||||||
Non-regulatory agreement units | 13 | 13 | 0 | 0 | 0 | |||||||||||||
Net unrealized gains on pledged assets | ||||||||||||||||||
Zion Station decommissioning | 10 | 10 | 0 | 0 | 0 | |||||||||||||
Regulatory offset to decommissioning trust fund-related | ||||||||||||||||||
activities (b) | -94 | -94 | 0 | 0 | 0 | |||||||||||||
Total decommissioning-related activities | 58 | 58 | 0 | 0 | 0 | |||||||||||||
Investment income (expense) | 1 | 1 | 0 | 0 | 2 | (c) | ||||||||||||
Long-term lease income | 6 | 0 | 0 | 0 | 0 | |||||||||||||
Interest income related to uncertain income tax positions | 10 | 14 | 0 | 0 | 0 | |||||||||||||
AFUDC - Equity | 6 | 0 | 3 | 1 | 3 | |||||||||||||
Other | 22 | 17 | 2 | 1 | -1 | |||||||||||||
Other, net | $ | 103 | $ | 90 | $ | 5 | $ | 2 | $ | 4 | ||||||||
Three Months Ended March 31, 2013 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||
Other, Net | ||||||||||||||||||
Decommissioning-related activities: | ||||||||||||||||||
Net realized income on decommissioning trust funds (a) | ||||||||||||||||||
Regulatory agreement units | $ | 36 | $ | 36 | $ | 0 | $ | 0 | $ | 0 | ||||||||
Non-regulatory agreement units | 14 | 14 | 0 | 0 | 0 | |||||||||||||
Net unrealized gains on decommissioning trust funds | ||||||||||||||||||
Regulatory agreement units | 195 | 195 | 0 | 0 | 0 | |||||||||||||
Non-regulatory agreement units | 64 | 64 | 0 | 0 | 0 | |||||||||||||
Net unrealized gains on pledged assets | ||||||||||||||||||
Zion Station decommissioning | 2 | 2 | 0 | 0 | 0 | |||||||||||||
Regulatory offset to decommissioning trust fund-related | ||||||||||||||||||
activities (b) | -190 | -190 | 0 | 0 | 0 | |||||||||||||
Total decommissioning-related activities | 121 | 121 | 0 | 0 | 0 | |||||||||||||
Investment income (expense) | 3 | -2 | 0 | 0 | 2 | (c) | ||||||||||||
Long-term lease income | 8 | 0 | 0 | 0 | 0 | |||||||||||||
Interest income related to uncertain income tax provisions | 25 | 5 | 0 | 0 | 0 | |||||||||||||
AFUDC - Equity | 6 | 0 | 3 | 1 | 2 | |||||||||||||
Other | 9 | 4 | 2 | 2 | 1 | |||||||||||||
Other, net | $ | 172 | $ | 128 | $ | 5 | $ | 3 | $ | 5 | ||||||||
__________ | ||||||||||||||||||
(a) Includes investment income and realized gains and losses on sales of investments of the trust funds. | ||||||||||||||||||
(b) Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of net income taxes related to all NDT fund activity for those units. See Note 15 – Asset Retirement Obligations of the Exelon 2013 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 4 - 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 three months ended March 31, 2014 and 2013: | ||||||||||||||||||
Three Months Ended March 31, 2014 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||
Depreciation, amortization, accretion and depletion | ||||||||||||||||||
Property, plant and equipment | $ | 481 | $ | 200 | $ | 143 | $ | 56 | $ | 70 | ||||||||
Regulatory assets | 72 | 0 | 30 | 2 | 38 | |||||||||||||
Amortization of intangible assets, net | 11 | 11 | 0 | 0 | 0 | |||||||||||||
Amortization of energy contract assets and liabilities (a) | 42 | 44 | 0 | 0 | 0 | |||||||||||||
Nuclear fuel (b) | 234 | 234 | 0 | 0 | 0 | |||||||||||||
ARO accretion (c) | 68 | 68 | 0 | 0 | 0 | |||||||||||||
Total depreciation, amortization, accretion and depletion | $ | 908 | $ | 557 | $ | 173 | $ | 58 | $ | 108 | ||||||||
Three Months Ended March 31, 2013 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||
Depreciation, amortization, accretion and depletion | ||||||||||||||||||
Property, plant and equipment | $ | 471 | $ | 203 | $ | 137 | $ | 55 | $ | 64 | ||||||||
Regulatory assets | 61 | 0 | 30 | 2 | 29 | |||||||||||||
Amortization of intangible assets, net | 11 | 11 | 0 | 0 | 0 | |||||||||||||
Amortization of energy contract assets and liabilities (a) | 176 | 176 | 0 | 0 | 0 | |||||||||||||
Nuclear fuel (b) | 230 | 230 | 0 | 0 | 0 | |||||||||||||
ARO accretion (c) | 68 | 68 | 0 | 0 | 0 | |||||||||||||
Total depreciation, amortization, accretion and depletion | $ | 1,017 | $ | 688 | $ | 167 | $ | 57 | $ | 93 | ||||||||
__________ | ||||||||||||||||||
(a) Included in Operating revenues or Purchased power and fuel expense on the Registrants' Consolidated Statements of Operations and Comprehensive Income. | ||||||||||||||||||
(b) Included in Purchased power and fuel expense on the Registrants' Consolidated Statements of Operations and Comprehensive Income. | ||||||||||||||||||
(c) Included in Operating and maintenance expense on the Registrants' Consolidated Statements of Operations and Comprehensive Income. | ||||||||||||||||||
Three Months Ended March 31, 2014 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||
Other non-cash operating activities: | ||||||||||||||||||
Pension and non-pension postretirement benefit costs | $ | 173 | $ | 75 | $ | 56 | $ | 12 | $ | 16 | ||||||||
Loss from equity method investments | 19 | 19 | 0 | 0 | 0 | |||||||||||||
Provision for uncollectible accounts | 35 | 1 | -11 | 35 | 11 | |||||||||||||
Stock-based compensation costs | 46 | 0 | 0 | 0 | 0 | |||||||||||||
Other decommissioning-related activity (a) | -35 | -35 | 0 | 0 | 0 | |||||||||||||
Energy-related options (b) | 31 | 31 | 0 | 0 | 0 | |||||||||||||
Amortization of regulatory asset related to debt costs | 3 | 0 | 2 | 1 | 0 | |||||||||||||
Amortization of rate stabilization deferral | 20 | 0 | 0 | 0 | 20 | |||||||||||||
Amortization of debt fair value adjustment | -12 | -5 | 0 | 0 | 0 | |||||||||||||
Discrete impacts of EIMA (c) | -4 | 0 | -4 | 0 | 0 | |||||||||||||
Amortization of debt costs | 5 | 3 | -5 | 1 | 0 | |||||||||||||
Increase in inventory reserve | 2 | 2 | 0 | 0 | 0 | |||||||||||||
Other | -11 | -6 | -2 | 0 | -4 | |||||||||||||
Total other non-cash operating activities | $ | 272 | $ | 85 | $ | 36 | $ | 49 | $ | 43 | ||||||||
Changes in other assets and liabilities: | ||||||||||||||||||
Under/over-recovered energy and transmission costs | $ | -15 | $ | 0 | $ | 4 | $ | -17 | $ | 23 | ||||||||
Other regulatory assets and liabilities | -4 | 0 | -10 | -3 | 6 | |||||||||||||
Other current assets | -209 | -80 | -29 | -105 | (e) | 18 | ||||||||||||
Other noncurrent assets and liabilities | -50 | -23 | 11 | -2 | -3 | |||||||||||||
Total changes in other assets and liabilities | $ | -278 | $ | -103 | $ | -24 | $ | -127 | $ | 44 | ||||||||
Non-cash investing and financing activities: | ||||||||||||||||||
Indemnification of like-kind exchange position (f) | $ | 0 | $ | 0 | $ | 2 | $ | 0 | $ | 0 | ||||||||
Total non-cash investing and financing activities: | $ | 0 | $ | 0 | $ | 2 | $ | 0 | $ | 0 | ||||||||
Three Months Ended March 31, 2013 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||
Other non-cash operating activities: | ||||||||||||||||||
Pension and non-pension postretirement benefit costs | $ | 205 | $ | 87 | $ | 77 | $ | 11 | $ | 14 | ||||||||
Loss in equity method investments | 9 | 9 | 0 | 0 | 0 | |||||||||||||
Provision for uncollectible accounts | 45 | 7 | 9 | 25 | 4 | |||||||||||||
Stock-based compensation costs | 39 | 4 | 1 | 1 | 1 | |||||||||||||
Other decommissioning-related activity (a) | -64 | -64 | 0 | 0 | 0 | |||||||||||||
Energy-related options (b) | 21 | 21 | 0 | 0 | 0 | |||||||||||||
Amortization of regulatory asset related to debt costs | 4 | 0 | 3 | 1 | 0 | |||||||||||||
Amortization of rate stabilization deferral | 30 | 0 | 0 | 0 | 30 | |||||||||||||
Amortization of debt fair value adjustment | -9 | -9 | 0 | 0 | 0 | |||||||||||||
Discrete impacts from EIMA (c) | -49 | 0 | -49 | 0 | 0 | |||||||||||||
Amortization of debt costs | 5 | 3 | 1 | 1 | 0 | |||||||||||||
Merger integration costs (d) | -6 | 0 | 0 | 0 | -6 | |||||||||||||
Other | 1 | 8 | 0 | 0 | -1 | |||||||||||||
Total other non-cash operating activities | $ | 231 | $ | 66 | $ | 42 | $ | 39 | $ | 42 | ||||||||
Changes in other assets and liabilities: | ||||||||||||||||||
Under/over-recovered energy and transmission costs | $ | 29 | $ | 0 | $ | -18 | $ | 22 | $ | 16 | ||||||||
Other regulatory assets and liabilities | 91 | 0 | -14 | 13 | -53 | |||||||||||||
Other current assets | -169 | -131 | 17 | -75 | (e) | 73 | ||||||||||||
Other noncurrent assets and liabilities | 282 | -28 | 263 | 2 | -2 | |||||||||||||
Total changes in other assets and liabilities | $ | 233 | $ | -159 | $ | 248 | $ | -38 | $ | 34 | ||||||||
Non-cash investing and financing activities: | ||||||||||||||||||
Consolidated VIE dividend to non-controlling interest | $ | 63 | 63 | 0 | 0 | 0 | ||||||||||||
Indemnification of like-kind exchange position (f) | 0 | 0 | 172 | 0 | 0 | |||||||||||||
Total non-cash investing and financing activities | $ | 63 | $ | 63 | $ | 172 | $ | 0 | $ | 0 | ||||||||
Other Investing Activities (Exelon and Generation). Other investing activities for Exelon and Generation primarily represents cash flows associated with the acquisition or disposition of immaterial investments. | ||||||||||||||||||
DOE Smart Grid Investment Grant (Exelon, BGE and PECO). For the three months ended March 31, 2014, PECO has included in the capital expenditures line item under investing activities of the cash flow statement capital expenditures of $2 million and reimbursements of $2 million related to PECO's DOE SGIG programs. For the three months ended March 31, 2013, Exelon, PECO and BGE have included in the capital expenditures line item under investing activities of the cash flow statement capital expenditures of $21 million, $6 million and $15 million, respectively, and reimbursements of $32 million, $12 million and $20 million, respectively, related to PECO's and BGE's DOE SGIG programs. See Note 4 - Regulatory Matters for additional information regarding the DOE SGIG. | ||||||||||||||||||
_________ | ||||||||||||||||||
(a) Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 15 of the Exelon 2013 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 4 - Regulatory Matters for more information. | ||||||||||||||||||
(d) Relates to integration costs to achieve distribution synergies related to the merger transaction. See Note 4 - Regulatory Matters for more information. | ||||||||||||||||||
(e) Relates primarily to prepaid utility taxes. | ||||||||||||||||||
(f) See Note 9 – Income Taxes for discussion of the like-kind exchange tax position. | ||||||||||||||||||
Supplemental Balance Sheet Information | ||||||||||||||||||
The following tables provide additional information about assets and liabilities of the Registrants as of March 31, 2014 and December 31, 2013. | ||||||||||||||||||
31-Mar-14 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||
Property, plant and equipment: | ||||||||||||||||||
Accumulated depreciation and amortization | $ | 14,066 | (a) | $ | 7,245 | (a) | $ | 3,247 | $ | 2,958 | $ | 2,741 | ||||||
Accounts receivable: | ||||||||||||||||||
Allowance for uncollectible accounts | 306 | 46 | 76 | 140 | 44 | |||||||||||||
31-Dec-13 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||
Property, plant and equipment: | ||||||||||||||||||
Accumulated depreciation and amortization | $ | 13,713 | (b) | $ | 7,034 | (b) | $ | 3,184 | $ | 2,935 | $ | 2,702 | ||||||
Accounts receivable: | ||||||||||||||||||
Allowance for uncollectible accounts | 272 | 57 | 62 | 107 | 46 | |||||||||||||
___________ | ||||||||||||||||||
(a) Includes accumulated amortization of nuclear fuel in the reactor core of $2,425 million. | ||||||||||||||||||
(b) Includes accumulated amortization of nuclear fuel in the reactor core of $2,371 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 $18 million as of March 31, 2014 and $19 million as of December 31, 2013. 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 2013 Form 10-K. The allowance for uncollectible accounts balance associated with these receivables at March 31, 2014 of $15 million consists of $1 million, $4 million and $10 million for low risk, medium risk and high risk segments, respectively. The allowance for uncollectible accounts balance at December 31, 2013 of $18 million consists of $1 million, $4 million and $13 million for low risk, medium risk and high risk segments, respectively. The balance of the payment agreement is billed to the customer in equal monthly installments over the term of the agreement. Installment receivables outstanding as of March 31, 2014 and December 31, 2013 include balances not yet presented on the customer bill, accounts currently billed and an immaterial amount of past due receivables. When a customer defaults on its payment agreement, the terms of which are defined by plan type, the entire balance of the agreement becomes due and the balance is reclassified to current customer accounts receivable and reserved for in accordance with the methodology discussed in Note 1 – Significant Accounting Policies of the Exelon 2013 Form 10-K. | ||||||||||||||||||
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 9 – 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 arrange for a third-party to bid on a service contract for a period following the lease term. 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. | ||||||||||||||||||
On February 26, 2014, UII and the City Public Service Board of San Antonio, Texas (CPS) finalized an agreement to terminate the leases on the generating station located in Texas, as described above, prior to their expiration dates. As a result of the lease termination, UII received a net early termination amount of $335 million from CPS and wrote off the net investment in the CPS long-term lease of $336 million in Investments in the Consolidated Balance Sheet; resulting in a pre-tax loss of $1 million being reflected in Operating and maintenance expense in the Consolidated Statement of Operations and Comprehensive Income. See Note 9 – Income Taxes for impact of the lease termination on income taxes. | ||||||||||||||||||
At March 31, 2014 and December 31, 2013, the components of the net investment in long-term leases were as follows: | ||||||||||||||||||
31-Mar-14 | 31-Dec-13 | |||||||||||||||||
Estimated residual value of leased assets | $ | 731 | $ | 1,465 | ||||||||||||||
Less: unearned income | 363 | 767 | ||||||||||||||||
Net investment in long-term leases | $ | 368 | $ | 698 |
Segment_Information_Exelon_Gen
Segment Information (Exelon, Generation, ComEd, PECO and BGE) | 3 Months Ended | ||||||||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||||||||
Segment Information [Line Items] | ' | ||||||||||||||||||||||
Segment Information (Exelon, Generation, ComEd, PECO and BGE) | ' | ||||||||||||||||||||||
17. Segment Information (Exelon, Generation, ComEd, PECO and BGE) | |||||||||||||||||||||||
Operating segments for each of the Registrants are determined based on information used by the chief operating decision maker(s) (CODM) in deciding how to evaluate performance and allocate resources at each of the Registrants. | |||||||||||||||||||||||
Exelon has nine reportable segments, ComEd, PECO, BGE and Generation's six power marketing reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and all other regions not considered individually significant referred to collectively as “Other Regions”; including the South, West and Canada. ComEd, PECO and BGE each represent a single reportable segment; as such, no separate segment information is provided for these Registrants. Exelon evaluates the performance of ComEd, PECO and BGE based on net income and return on equity. | |||||||||||||||||||||||
The CODMs for ComEd, PECO, and BGE evaluate performance and allocate resources for their respective companies based on net income and return on equity for ComEd, PECO, and BGE each as single integrated businesses. | |||||||||||||||||||||||
The foundation of Generation's six reportable segments is based on the geographic location of its assets, and is largely representative of the footprints of an ISO / RTO and/or NERC region. Descriptions of each of Generation's six reportable segments are as follows: | |||||||||||||||||||||||
Mid-Atlantic represents operations in the eastern half of PJM, which includes Pennsylvania, New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia and parts of North Carolina. | |||||||||||||||||||||||
Midwest represents operations in the western half of PJM, which includes portions of Illinois, Indiana, Ohio, Michigan, Kentucky and Tennessee, and the United States footprint of MISO excluding MISO's Southern Region, which covers all or most of North Dakota, South Dakota, Nebraska, Minnesota, Iowa, Wisconsin, the remaining parts of Illinois, Indiana, Michigan and Ohio not covered by PJM, and parts of Montana, Missouri and Kentucky. | |||||||||||||||||||||||
New England represents the operations within ISO-NE covering the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont. | |||||||||||||||||||||||
New York represents operations within ISO-NY, which covers the state of New York in its entirety. | |||||||||||||||||||||||
ERCOT represents operations within Electric Reliability Council of Texas, covering most of the state of Texas. | |||||||||||||||||||||||
Other Regions not considered individually significant: | |||||||||||||||||||||||
South represents operations in the FRCC, MISO's Southern Region, and the remaining portions of the SERC not included within MISO or PJM, which includes all or most of Florida, Arkansas, Louisiana, Mississippi, Alabama, Georgia, Tennessee, North Carolina, South Carolina and parts of Missouri, Kentucky and Texas. Generation's South region also includes operations in the SPP, covering Kansas, Oklahoma, most of Nebraska and parts of New Mexico, Texas, Louisiana, Missouri, Mississippi and Arkansas. | |||||||||||||||||||||||
West represents operations in the WECC, which includes California ISO, and covers the states of California, Oregon, Washington, Arizona, Nevada, Utah, Idaho, Colorado, and parts of New Mexico, Wyoming and South Dakota. | |||||||||||||||||||||||
Canada represents operations across the entire country of Canada and includes the AESO, OIESO and the Canadian portion of MISO. | |||||||||||||||||||||||
The CODMs for Exelon and Generation evaluate the performance of Generation's power marketing activities and allocate resources based on revenue net of purchased power and fuel expense. Generation believes that revenue net of purchased power and fuel expense is a useful measurement of operational performance. Revenue net of purchased power and fuel expense is not a presentation defined under GAAP and may not be comparable to other companies' presentations or deemed more useful than the GAAP information provided elsewhere in this report. Generation's operating revenues include all sales to third parties and 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 other miscellaneous revenues, unrealized mark-to-market impact of economic hedging activities, and amortization of certain intangible assets relating to commodity contracts recorded at fair value 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 months ended March 31, 2014 and 2013 is as follows: | |||||||||||||||||||||||
Intersegment Eliminations | |||||||||||||||||||||||
Generation (a) | ComEd | PECO | BGE | Other (b) | Exelon | ||||||||||||||||||
Total revenues (c): | |||||||||||||||||||||||
2014 | $ | 4,390 | $ | 1,134 | $ | 993 | $ | 1,054 | $ | 290 | $ | -624 | $ | 7,237 | |||||||||
2013 | 3,533 | 1,160 | 895 | 880 | 318 | -704 | 6,082 | ||||||||||||||||
Intersegment revenues (d): | |||||||||||||||||||||||
2014 | $ | 316 | $ | 1 | $ | 1 | $ | 16 | $ | 290 | $ | -623 | $ | 1 | |||||||||
2013 | 381 | 1 | 0 | 4 | 318 | -704 | 0 | ||||||||||||||||
Net income (loss): | |||||||||||||||||||||||
2014 | $ | -185 | $ | 98 | $ | 89 | $ | 88 | $ | 4 | $ | -1 | $ | 93 | |||||||||
2013 | -17 | -81 | 122 | 80 | -103 | 0 | 1 | ||||||||||||||||
Total assets: | |||||||||||||||||||||||
31-Mar-14 | $ | 41,080 | $ | 24,294 | $ | 9,766 | $ | 7,958 | $ | 8,146 | $ | -11,776 | $ | 79,468 | |||||||||
31-Dec-13 | 41,232 | 24,118 | 9,617 | 7,861 | 8,317 | -11,221 | 79,924 | ||||||||||||||||
__________ | |||||||||||||||||||||||
(a) Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions. Intersegment revenues for Generation for the three months ended March 31, 2014 include revenue from sales to PECO of $88 million and sales to BGE of $120 million in the Mid-Atlantic region, and sales to ComEd of $108 million in the Midwest. For the three months ended March 31, 2013 intersegment revenues for Generation include revenue from sales to PECO of $141 million and sales to BGE of $113 million in the Mid-Atlantic region, and sales to ComEd of $145 million in the Midwest region, net of ($17) 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 March 31, 2014 and 2013, utility taxes of $24 million and $21 million, respectively, are included in revenues and expenses for Generation. For the three months ended March 31, 2014 and 2013, utility taxes of $63 million and $60 million, respectively, are included in revenues and expenses for ComEd. For the three months ended March 31, 2014 and 2013, utility taxes of $35 million and $34 million, respectively, are included in revenues and expenses for PECO. For the three months ended March 31, 2014 and 2013, utility taxes of $20 million and $22 million, respectively, are included in revenues and expenses for BGE. | |||||||||||||||||||||||
(d) Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation's sale of certain products and services by and between Exelon's segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in operating revenues in the Consolidated Statements of Operations and Comprehensive Income. | |||||||||||||||||||||||
Generation total revenues (three months ended): | |||||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||||
Revenues from external customers (a) | Intersegment revenues | Total Revenues | Revenues from external customers (a) | Intersegment revenues | Total Revenues | ||||||||||||||||||
Mid-Atlantic | $ | 1,441 | $ | -23 | $ | 1,418 | $ | 1,331 | $ | -8 | $ | 1,323 | |||||||||||
Midwest | 1,258 | 12 | 1,270 | 1,181 | 7 | 1,188 | |||||||||||||||||
New England | 545 | 4 | 549 | 391 | 12 | 403 | |||||||||||||||||
New York | 190 | -3 | 187 | 175 | -6 | 169 | |||||||||||||||||
ERCOT | 243 | 0 | 243 | 293 | - | 293 | |||||||||||||||||
Other Regions (b) | 334 | 7 | 341 | 183 | 42 | 225 | |||||||||||||||||
Total Revenues for Reportable Segments | 4,011 | -3 | 4,008 | 3,554 | 47 | 3,601 | |||||||||||||||||
Other (c) | 379 | 3 | 382 | -21 | -47 | -68 | |||||||||||||||||
Total Generation Consolidated Operating Revenues | $ | 4,390 | $ | 0 | $ | 4,390 | $ | 3,533 | $ | - | $ | 3,533 | |||||||||||
(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 $93 million and $174 million, for the three months ended March 31, 2014 and 2013, respectively, and elimination of intersegment revenues. | |||||||||||||||||||||||
Generation total revenues net of purchased power and fuel expense (three months ended): | |||||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||||
RNF from external customers (a) | Intersegment RNF | Total RNF | RNF from external customers (a) | Intersegment RNF | Total RNF | ||||||||||||||||||
Mid-Atlantic | $ | 784 | $ | -89 | $ | 695 | $ | 852 | $ | -8 | $ | 844 | |||||||||||
Midwest | 530 | 26 | 556 | 710 | 7 | 717 | |||||||||||||||||
New England | 154 | -18 | 136 | 18 | 12 | 30 | |||||||||||||||||
New York | -29 | 8 | -21 | -16 | -6 | -22 | |||||||||||||||||
ERCOT | 155 | -72 | 83 | 112 | -11 | 101 | |||||||||||||||||
Other Regions (b) | 150 | -45 | 105 | 10 | 35 | 45 | |||||||||||||||||
Total Revenues net of purchased power and fuel expense for Reportable Segments | 1,744 | -190 | 1,554 | 1,686 | 29 | 1,715 | |||||||||||||||||
Other (c) | -711 | 190 | -521 | -322 | -29 | -351 | |||||||||||||||||
Total Generation Revenues net of purchased power and fuel expense | $ | 1,033 | $ | 0 | $ | 1,033 | $ | 1,364 | $ | - | $ | 1,364 | |||||||||||
(a) Includes purchases and sales from third parties and affiliated sales to ComEd, PECO and BGE. | |||||||||||||||||||||||
(b) Other regions include the South, West and Canada, which are not considered individually significant. | |||||||||||||||||||||||
(c) Other represents activities not allocated to a region. See text above for a description of included activities. Also includes amortization of intangible assets related to commodity contracts recorded at fair value of $42 million and $174 million for the three months ended March 31, 2014 and 2013, respectively, and the elimination of intersegment revenues. | |||||||||||||||||||||||
Subsequent_Events_Exelon_PECO_
Subsequent Events (Exelon, PECO and BGE) | 3 Months Ended |
Mar. 31, 2014 | |
Subsequent Events Disclosure [Line Items] | ' |
Subsequent Events TextBlock (Exelon, PECO and BGE) | ' |
18. Subsequent Events (Exelon) | |
Proposed Merger with Pepco Holdings, Inc. (Exelon) | |
On April 29, 2014, Exelon and Pepco Holdings, Inc. (PHI) signed an agreement and plan of merger to combine the two companies in an all cash transaction. The resulting company will retain the Exelon name and be headquartered in Chicago. Under the merger agreement, PHI's shareholders will receive $27.25 of cash in exchange for each share of PHI common stock. Exelon intends to fund the all-cash transaction using a combination of approximately 50% debt and the remainder through issuance of equity (including mandatory convertibles) and up to $1 billion cash from non-core asset sales. In addition, Exelon signed a 364-day $7.2 billion senior unsecured bridge credit facility in place to support the contemplated transaction and provide flexibility for timing of permanent financing. In connection with the merger agreement, Exelon entered into a subscription agreement to purchase $90 million of nonvoting, nonconvertible and nontransferable preferred securities in PHI, with additional investments to be made of $18 million quarterly up to a maximum aggregate investment of $180 million. | |
The transaction must be approved by the shareholders of PHI. Completion of the transaction is also conditioned upon approval by the FERC, the District of Columbia Public Service Commission and several state commissions including Delaware Public Service Commission, MDPSC, the New Jersey Board of Public Utilities and the Virginia Department of Public Utilities. In addition, under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (HSR Act), the transaction cannot be completed until Exelon has made required notifications and given certain information and materials to the Federal Trade Commission (FTC) and/or the Antitrust Division of the United States Department of Justice (DOJ) and until specified waiting period requirements have expired. | |
As part of the application for approval of the merger, Exelon and PHI have proposed a package of benefits to PHI utilities' customers which results in a direct investment of more than $100 million. The Merger Agreement also provides for termination rights on behalf of both parties. Under certain circumstances, if the merger agreement is terminated, PHI may be required to pay Exelon a termination fee ranging from $259 million to $293 million plus certain expenses. If the merger agreement does not close due to a regulatory failure, Exelon may be required to pay PHI a termination fee equal to the nonvoting preferred securities (described above), by means of PHI redeeming the nonvoting preferred securities for no consideration. The companies anticipate closing the transaction in the first half of 2015. Refer to the Current Report on Form 8-K filed on April 30, 2014 for additional information on the merger transaction. |
Fair_Value_of_Financial_Assets1
Fair Value of Financial Assets and Liabilities (Policies) | 3 Months Ended |
Mar. 31, 2014 | |
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 satisfy Generation's nuclear decommissioning obligations as required by the NRC. The NDT funds hold debt and equity securities directly and indirectly through commingled funds. Generation's investment policies place limitations on the types and investment grade ratings of the securities that may be held by the trusts. These policies limit the trust funds' exposures to investments in highly illiquid markets and other alternative investments. Investments with maturities of three months or less when purchased, including certain short-term fixed income securities are considered cash equivalents and included in the recurring fair value measurements hierarchy as Level 1 or Level 2. | |
With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are obtained from direct feeds from market exchanges, which Generation is able to independently corroborate. The fair values of equity securities held directly by the trust funds are based on quoted prices in active markets and are categorized in Level 1. Equity securities held individually are primarily traded on the New York Stock Exchange and NASDAQ-Global Select Market, which contain only actively traded securities due to the volume trading requirements imposed by these exchanges. | |
For fixed income securities, multiple prices from pricing services are obtained whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class or issue for each security. The trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another price source is considered to be preferable. Generation has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Generation selectively corroborates the fair values of securities by comparison to other market-based price sources. U.S. Treasury securities are categorized as Level 1 because they trade in a highly liquid and transparent market. The fair values of fixed income securities, excluding U.S. Treasury securities, are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities, adjusted for observable differences and are categorized in Level 2. The fair values of private placement fixed income securities are determined using a third party valuation that contains significant unobservable inputs and are categorized in Level 3. | |
Equity and fixed income commingled funds and fixed income mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives. The fair values of fixed income commingled and mutual funds held within the trust funds, which generally hold short-term fixed income securities and are not subject to restrictions regarding the purchase or sale of shares, are derived from observable prices. The objectives of the remaining equity commingled funds in which Exelon and Generation invest primarily seek to track the performance of certain equity indices by purchasing equity securities to replicate the capitalization and characteristics of the indices. Comingled 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 10 — Nuclear Decommissioning for further discussion on the NDT fund investments. | |
Middle market lending are investments in loans or managed funds which invest in private companies. Generation elected the fair value option for its investments in certain limited partnerships that invest in middle market lending managed funds. The fair value of these loans is determined using a combination of valuation models including cost models, market models, and income models. Investments in middle market lending are categorized as Level 3 because the fair value of these securities is based largely on inputs that are unobservable and utilize complex valuation models. Investments in middle market lending typically cannot be redeemed until maturity of the term loan. | |
As of March 31, 2014, Generation has outstanding commitments to invest in middle market lending, corporate debt securities, private equity investments, and real estate investments of approximately $469 million. These commitments will be funded by Generation's existing nuclear decommissioning trust funds. | |
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 and consist primarily of mutual funds. These funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives, which are consistent with Exelon's overall investment strategy. Mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability of the prices. | |
Mark-to-Market 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. | |
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 7 — 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 as Level 2 in the fair value hierarchy. |
Variable_Interest_Entities_Tab
Variable Interest Entities (Tables) | 3 Months Ended | ||||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||||
Variable Interest Entity [Line Items] | ' | ||||||||||||||||||
Schedule of Variable Interest Entities [Table Text Block] | ' | ||||||||||||||||||
31-Mar-14 | 31-Dec-13 | ||||||||||||||||||
Exelon (a) | Generation | BGE | Exelon (a) | Generation | BGE | ||||||||||||||
Current assets | $ | 738 | $ | 679 | $ | 53 | $ | 484 | $ | 446 | $ | 28 | |||||||
Noncurrent assets | 1,893 | 1,870 | 3 | 1,905 | 1,884 | 3 | |||||||||||||
Total assets | $ | 2,631 | $ | 2,549 | $ | 56 | $ | 2,389 | $ | 2,330 | $ | 31 | |||||||
Current liabilities | $ | 608 | $ | 525 | $ | 78 | $ | 566 | $ | 481 | $ | 74 | |||||||
Noncurrent liabilities | 780 | 566 | 195 | 774 | 562 | 195 | |||||||||||||
Total liabilities | $ | 1,388 | $ | 1,091 | $ | 273 | $ | 1,340 | $ | 1,043 | $ | 269 | |||||||
Schedule Of Unconsolidated Variable Interest Entities [Text Block] | ' | ||||||||||||||||||
Commercial | Equity | ||||||||||||||||||
Agreement | Investment | ||||||||||||||||||
31-Mar-14 | VIEs | VIEs | Total | ||||||||||||||||
Total assets (a) | $ | 113 | $ | 344 | $ | 457 | |||||||||||||
Total liabilities (a) | 2 | 139 | 141 | ||||||||||||||||
Registrants' ownership interest (a) | 0 | 64 | 64 | ||||||||||||||||
Other ownership interests (a) | 111 | 143 | 254 | ||||||||||||||||
Registrants' maximum exposure to loss: | |||||||||||||||||||
Carrying amount of equity method investments | 0 | 73 | 73 | ||||||||||||||||
Contract intangible asset | 9 | 0 | 9 | ||||||||||||||||
Debt and payment guarantees | 0 | 3 | 3 | ||||||||||||||||
Net assets pledged for Zion Station decommissioning (b) | 44 | 0 | 44 | ||||||||||||||||
Commercial | Equity | ||||||||||||||||||
Agreement | Investment | ||||||||||||||||||
31-Dec-13 | VIEs | VIEs | Total | ||||||||||||||||
Total assets (a) | $ | 128 | $ | 332 | $ | 460 | |||||||||||||
Total liabilities (a) | 17 | 123 | 140 | ||||||||||||||||
Registrants' ownership interest (a) | 0 | 86 | 86 | ||||||||||||||||
Other ownership interests (a) | 111 | 123 | 234 | ||||||||||||||||
Registrants' maximum exposure to loss: | |||||||||||||||||||
Carrying amount of equity method investments | 7 | 67 | 74 | ||||||||||||||||
Contract intangible asset | 9 | 0 | 9 | ||||||||||||||||
Debt and payment guarantees | 0 | 5 | 5 | ||||||||||||||||
Net assets pledged for Zion Station decommissioning (b) | 44 | 0 | 44 | ||||||||||||||||
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 $429 million and $458 million as of March 31, 2014 and December 31, 2013, respectively; offset by payables to ZionSolutions LLC of $385 million and $414 million as of March 31, 2014 and December 31, 2013, 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) | 3 Months Ended | ||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||
Business Acquisition [Line Items] | ' | ||||||||||||||||
Schedule Of Severance Costs [TableTextBlock] | ' | ||||||||||||||||
Severance Benefits | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||
Severance charges - 2014 | $ | 4 | $ | 4 | $ | 0 | $ | 0 | $ | 0 | |||||||
Severance charges - 2013 | 1 | 0 | 1 | 0 | 0 |
Regulatory_Matters_Tables
Regulatory Matters (Tables) | 3 Months Ended | ||||||||||||||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||||||||||||||
Regulatory Matters [Line Items] | ' | ||||||||||||||||||||||||||||
Regulatory assets and liabilities | ' | ||||||||||||||||||||||||||||
31-Mar-14 | Exelon | ComEd | PECO | BGE | |||||||||||||||||||||||||
Regulatory assets | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | |||||||||||||||||||||
Pension and other postretirement | |||||||||||||||||||||||||||||
benefits | $ | 218 | $ | 2,777 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | |||||||||||||
Deferred income taxes | 14 | 1,474 | 2 | 67 | 0 | 1,333 | 12 | 74 | |||||||||||||||||||||
AMI programs | 6 | 186 | 6 | 43 | 0 | 65 | 0 | 78 | |||||||||||||||||||||
Under-recovered distribution service | |||||||||||||||||||||||||||||
costs | 197 | 262 | 197 | 262 | 0 | 0 | 0 | 0 | |||||||||||||||||||||
Debt costs | 12 | 54 | 9 | 51 | 3 | 3 | 1 | 8 | |||||||||||||||||||||
Fair value of BGE long-term debt (a) | 6 | 206 | 0 | 0 | 0 | 0 | 0 | 0 | |||||||||||||||||||||
Fair value of BGE supply contract (b) | 9 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | |||||||||||||||||||||
Severance | 10 | 12 | 6 | 0 | 0 | 0 | 4 | 12 | |||||||||||||||||||||
Asset retirement obligations | 1 | 108 | 1 | 72 | 0 | 25 | 0 | 11 | |||||||||||||||||||||
MGP remediation costs | 44 | 201 | 37 | 168 | 6 | 32 | 1 | 1 | |||||||||||||||||||||
RTO start-up costs | 2 | 0 | 2 | 0 | 0 | 0 | 0 | 0 | |||||||||||||||||||||
Under-recovered uncollectible | |||||||||||||||||||||||||||||
accounts | 0 | 74 | 0 | 74 | 0 | 0 | 0 | 0 | |||||||||||||||||||||
Renewable energy | 13 | 155 | 13 | 155 | 0 | 0 | 0 | 0 | |||||||||||||||||||||
Energy and transmission programs | 51 | 0 | 50 | 0 | 1 | 0 | 0 | 0 | |||||||||||||||||||||
Deferred storm costs | 3 | 2 | 0 | 0 | 0 | 0 | 3 | 2 | |||||||||||||||||||||
Electric generation-related | |||||||||||||||||||||||||||||
regulatory asset | 13 | 27 | 0 | 0 | 0 | 0 | 13 | 27 | |||||||||||||||||||||
Rate stabilization deferral | 72 | 133 | 0 | 0 | 0 | 0 | 72 | 133 | |||||||||||||||||||||
Energy efficiency and demand | |||||||||||||||||||||||||||||
response programs | 57 | 146 | 0 | 0 | 0 | 0 | 57 | 146 | |||||||||||||||||||||
Merger integration costs | 2 | 8 | 0 | 0 | 0 | 0 | 2 | 8 | |||||||||||||||||||||
Other | 38 | 38 | 17 | 26 | 18 | 7 | 3 | 4 | |||||||||||||||||||||
Total regulatory assets | $ | 768 | $ | 5,863 | $ | 340 | $ | 918 | $ | 28 | $ | 1,465 | $ | 168 | $ | 504 | |||||||||||||
31-Mar-14 | Exelon | ComEd | PECO | BGE | |||||||||||||||||||||||||
Regulatory liabilities | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | |||||||||||||||||||||
Other postretirement benefits | $ | 2 | $ | 47 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | |||||||||||||
Nuclear decommissioning | 0 | 2,774 | 0 | 2,319 | 0 | 455 | 0 | 0 | |||||||||||||||||||||
Removal costs | 105 | 1,440 | 81 | 1,237 | 0 | 0 | 24 | 203 | |||||||||||||||||||||
Energy efficiency and demand | |||||||||||||||||||||||||||||
response programs | 40 | 0 | 39 | 0 | 1 | 0 | 0 | 0 | |||||||||||||||||||||
DLC Program Costs | 1 | 11 | 0 | 0 | 1 | 11 | 0 | 0 | |||||||||||||||||||||
Energy efficiency Phase 2 | 0 | 31 | 0 | 0 | 0 | 31 | 0 | 0 | |||||||||||||||||||||
Electric distribution tax repairs | 22 | 108 | 0 | 0 | 22 | 108 | 0 | 0 | |||||||||||||||||||||
Gas distribution tax repairs | 8 | 36 | 0 | 0 | 8 | 36 | 0 | 0 | |||||||||||||||||||||
Energy and transmission programs | 76 | 10 | 0 | 10 | 43 | (c) | 0 | 33 | (f) | 0 | |||||||||||||||||||
Over-recovered gas and electric | |||||||||||||||||||||||||||||
universal service fund costs | 7 | 0 | 0 | 0 | 7 | 0 | 0 | 0 | |||||||||||||||||||||
Revenue subject to refund (d) | 38 | 0 | 38 | 0 | 0 | 0 | 0 | 0 | |||||||||||||||||||||
Over-recovered gas and electric | |||||||||||||||||||||||||||||
revenue decoupling (e) | 35 | 0 | 0 | 0 | 0 | 0 | 35 | 0 | |||||||||||||||||||||
Other | 2 | 1 | 0 | 0 | 2 | 0 | 0 | 0 | |||||||||||||||||||||
Total regulatory liabilities | $ | 336 | $ | 4,458 | $ | 158 | $ | 3,566 | $ | 84 | $ | 641 | $ | 92 | $ | 203 | |||||||||||||
31-Dec-13 | Exelon | ComEd | PECO | BGE | |||||||||||||||||||||||||
Regulatory assets | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | |||||||||||||||||||||
Pension and other postretirement | |||||||||||||||||||||||||||||
benefits | $ | 221 | $ | 2,794 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | |||||||||||||
Deferred income taxes | 10 | 1,459 | 2 | 65 | 0 | 1,317 | 8 | 77 | |||||||||||||||||||||
AMI programs | 5 | 159 | 5 | 35 | 0 | 58 | 0 | 66 | |||||||||||||||||||||
AMI meter events | 0 | 5 | 0 | 0 | 0 | 5 | 0 | 0 | |||||||||||||||||||||
Under-recovered distribution service | |||||||||||||||||||||||||||||
costs | 178 | 285 | 178 | 285 | 0 | 0 | 0 | 0 | |||||||||||||||||||||
Debt costs | 12 | 56 | 9 | 53 | 3 | 3 | 1 | 8 | |||||||||||||||||||||
Fair value of BGE long-term debt (a) | 0 | 219 | 0 | 0 | 0 | 0 | 0 | 0 | |||||||||||||||||||||
Fair value of BGE supply contract (b) | 12 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | |||||||||||||||||||||
Severance | 16 | 12 | 12 | 0 | 0 | 0 | 4 | 12 | |||||||||||||||||||||
Asset retirement obligations | 1 | 102 | 1 | 67 | 0 | 25 | 0 | 10 | |||||||||||||||||||||
MGP remediation costs | 40 | 212 | 33 | 178 | 6 | 33 | 1 | 1 | |||||||||||||||||||||
RTO start-up costs | 2 | 0 | 2 | 0 | 0 | 0 | 0 | 0 | |||||||||||||||||||||
Under-recovered uncollectible | |||||||||||||||||||||||||||||
accounts | 0 | 48 | 0 | 48 | 0 | 0 | 0 | 0 | |||||||||||||||||||||
Renewable energy | 17 | 176 | 17 | 176 | 0 | 0 | 0 | 0 | |||||||||||||||||||||
Energy and transmission programs | 53 | 0 | 52 | 0 | 0 | 0 | 1 | (f) | 0 | ||||||||||||||||||||
Deferred storm costs | 3 | 3 | 0 | 0 | 0 | 0 | 3 | 3 | |||||||||||||||||||||
Electric generation-related | |||||||||||||||||||||||||||||
regulatory asset | 13 | 30 | 0 | 0 | 0 | 0 | 13 | 30 | |||||||||||||||||||||
Rate stabilization deferral | 71 | 154 | 0 | 0 | 0 | 0 | 71 | 154 | |||||||||||||||||||||
Energy efficiency and demand | |||||||||||||||||||||||||||||
response programs | 73 | 148 | 0 | 0 | 0 | 0 | 73 | 148 | |||||||||||||||||||||
Merger integration costs | 2 | 9 | 0 | 0 | 0 | 0 | 2 | 9 | |||||||||||||||||||||
Other | 31 | 39 | 18 | 26 | 8 | 7 | 4 | 6 | |||||||||||||||||||||
Total regulatory assets | $ | 760 | $ | 5,910 | $ | 329 | $ | 933 | $ | 17 | $ | 1,448 | $ | 181 | $ | 524 | |||||||||||||
31-Dec-13 | Exelon | ComEd | PECO | BGE | |||||||||||||||||||||||||
Regulatory liabilities | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | |||||||||||||||||||||
Other postretirement benefits | $ | 2 | $ | 43 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | |||||||||||||
Nuclear decommissioning | 0 | 2,740 | 0 | 2,293 | 0 | 447 | 0 | 0 | |||||||||||||||||||||
Removal costs | 99 | 1,423 | 78 | 1,219 | 0 | 0 | 21 | 204 | |||||||||||||||||||||
Energy efficiency and demand | |||||||||||||||||||||||||||||
response programs | 53 | 0 | 45 | 0 | 8 | 0 | 0 | 0 | |||||||||||||||||||||
DLC Program Costs | 1 | 10 | 0 | 0 | 1 | 10 | 0 | 0 | |||||||||||||||||||||
Energy efficiency phase II | 0 | 21 | 0 | 0 | 0 | 21 | 0 | 0 | |||||||||||||||||||||
Electric distribution tax repairs | 20 | 114 | 0 | 0 | 20 | 114 | 0 | 0 | |||||||||||||||||||||
Gas distribution tax repairs | 8 | 37 | 0 | 0 | 8 | 37 | |||||||||||||||||||||||
Energy and transmission programs | 78 | 0 | 9 | 0 | 58 | (c) | 0 | 11 | (f) | 0 | |||||||||||||||||||
Over-recovered gas and electric | |||||||||||||||||||||||||||||
universal service fund costs | 8 | 0 | 0 | 0 | 8 | 0 | 0 | 0 | |||||||||||||||||||||
Revenue subject to refund (d) | 38 | 0 | 38 | 0 | 0 | 0 | 0 | 0 | |||||||||||||||||||||
Over-recovered electric and gas | |||||||||||||||||||||||||||||
revenue decoupling (e) | 16 | 0 | 0 | 0 | 0 | 0 | 16 | 0 | |||||||||||||||||||||
Other | 4 | 0 | 0 | 0 | 3 | 0 | 0 | 0 | |||||||||||||||||||||
Total regulatory liabilities | $ | 327 | $ | 4,388 | $ | 170 | $ | 3,512 | $ | 106 | $ | 629 | $ | 48 | $ | 204 | |||||||||||||
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 8 – 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. | |||||||||||||||||||||||||||||
Includes $32 million related to the DSP program, $0 million related to the over-recovered natural gas costs under the PGC and $11 million related to over-recovered electric transmission costs as of March 31, 2014. As of December 31, 2013, includes $34 million related to the DSP program, $8 million related to the over-recovered electric transmission costs and $16 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 Note 3 – Regulatory Matters of the Exelon 2013 Form 10-K. for further information. | |||||||||||||||||||||||||||||
Represents the electric and gas distribution costs recoverable from customers under BGE's decoupling mechanism. As of March 31, 2014, BGE had a regulatory liability of $14 million related to over-recovered electric revenue decoupling and $21 million related to over-recovered natural gas revenue decoupling. As of December 31, 2013, BGE had a regulatory liability of $7 million related to over-recovered electric revenue decoupling and $9 million related to over-recovered natural gas revenue decoupling. | |||||||||||||||||||||||||||||
Relates to $3 million of over-recovered electric supply costs and $30 million of over-recovered natural gas supply costs as of March 31, 2014. As of December 31, 2013, includes $1 million of under-recovered electric supply costs and $11 million of over-recovered natural gas supply costs. | |||||||||||||||||||||||||||||
As of March 31, 2014 | Exelon | ComEd | PECO | BGE | |||||||||||||||||||||||||
Purchased receivables (a) | $ | 330 | $ | 125 | $ | 93 | $ | 112 | |||||||||||||||||||||
Allowance for uncollectible accounts (b) | -36 | -19 | -10 | -7 | |||||||||||||||||||||||||
Purchased receivables, net | $ | 294 | $ | 106 | $ | 83 | $ | 105 | |||||||||||||||||||||
As of December 31, 2013 | Exelon | ComEd | PECO | BGE | |||||||||||||||||||||||||
Purchased receivables (a) | $ | 263 | $ | 105 | $ | 72 | $ | 86 | |||||||||||||||||||||
Allowance for uncollectible accounts (b) | -30 | -16 | -7 | -7 | |||||||||||||||||||||||||
Purchased receivables, net | $ | 233 | $ | 89 | $ | 65 | $ | 79 | |||||||||||||||||||||
__________ | |||||||||||||||||||||||||||||
(a) PECO's gas POR program became effective on January 1, 2012 and includes a 1% discount on purchased receivables in order to recover the implementation costs of the program. If the costs are not fully recovered when PECO files its next gas distribution rate case, PECO will propose a mechanism to recover the remaining implementation costs as a distribution charge to low volume transportation customers or apply future discounts on purchased receivables from natural gas suppliers serving those customers. | |||||||||||||||||||||||||||||
(b) For ComEd and BGE, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through its Purchase of Receivables with Consolidated Billing (PORCB) tariff. | |||||||||||||||||||||||||||||
Investment_in_Constellation_En1
Investment in Constellation Energy Nuclear Group, LLC (Tables) | 3 Months Ended | ||||||
Mar. 31, 2014 | |||||||
Schedule of Equity Method Investments [Line Items] | ' | ||||||
Schedule of total equity in earnings of investment in CENG | ' | ||||||
Three Months | Three Months | ||||||
Ended March 31, | Ended March 31, | ||||||
2014 | 2013 | ||||||
Equity investment income | $ | -2 | $ | 15 | |||
Amortization of basis difference in CENG | -17 | -27 | |||||
Total equity in earnings - CENG | $ | -19 | $ | -12 | |||
Exelon Generation Co L L C [Member] | ' | ||||||
Schedule of Equity Method Investments [Line Items] | ' | ||||||
Schedule of total equity in earnings of investment in CENG | ' | ||||||
Three Months | Three Months | ||||||
Ended March 31, | Ended March 31, | ||||||
2014 | 2013 | ||||||
Equity investment income | $ | -2 | $ | 15 | |||
Amortization of basis difference in CENG | -17 | -27 | |||||
Total equity in earnings - CENG | $ | -19 | $ | -12 |
Fair_Value_of_Financial_Assets2
Fair Value of Financial Assets and Liabilities (Tables) | 3 Months Ended | ||||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||||
Fair Value Tables [Line Items] | ' | ||||||||||||||||||
Fair value of financial liabilities recorded at the carrying amount | ' | ||||||||||||||||||
31-Mar-14 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Short-term liabilities | $ | 983 | $ | 3 | $ | 980 | $ | 0 | $ | 983 | |||||||||
Long-term debt (including amounts due within one year) | 18,920 | 0 | 18,976 | 1,066 | 20,042 | ||||||||||||||
Long-term debt to financing trusts | 648 | 0 | 0 | 648 | 648 | ||||||||||||||
SNF obligation | 1,021 | 0 | 840 | 0 | 840 | ||||||||||||||
31-Dec-13 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Short-term liabilities | $ | 344 | $ | 3 | $ | 341 | $ | 0 | $ | 344 | |||||||||
Long-term debt (including amounts due within one year) | 19,132 | 0 | 18,672 | 1,079 | 19,751 | ||||||||||||||
Long-term debt to financing trusts | 648 | 0 | 0 | 631 | 631 | ||||||||||||||
SNF obligation | 1,021 | 0 | 790 | 0 | 790 | ||||||||||||||
Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis | ' | ||||||||||||||||||
Three Months Ended March 31, 2014 | Nuclear Decommissioning Trust Fund Investments | Pledged Assets for Zion Station Decommissioning | Mark-to-Market Derivatives | Other Investments | Total | ||||||||||||||
Balance as of December 31, 2013 | $ | 350 | $ | 112 | $ | 272 | $ | 15 | $ | 749 | |||||||||
Total realized / unrealized gains (losses) | |||||||||||||||||||
Included in net income | 1 | 0 | -312 | (a) | 0 | -311 | |||||||||||||
Included in regulatory assets | 3 | 0 | 25 | 0 | 28 | ||||||||||||||
Included in payable for Zion Station decommissioning | 0 | -1 | 0 | 0 | -1 | ||||||||||||||
Change in collateral | 0 | 0 | 144 | 0 | 144 | ||||||||||||||
Purchases, sales, issuances and settlements | |||||||||||||||||||
Purchases | 139 | 30 | 10 | 2 | 181 | ||||||||||||||
Sales | -1 | -4 | -2 | 0 | -7 | ||||||||||||||
Settlements | -6 | 0 | 0 | 0 | -6 | ||||||||||||||
Transfers into Level 3 | 0 | 0 | -26 | 0 | -26 | ||||||||||||||
Transfers out of Level 3 | 0 | 0 | 8 | -7 | 1 | ||||||||||||||
Balance as of March 31, 2014 | $ | 486 | $ | 137 | $ | 119 | $ | 10 | $ | 752 | |||||||||
The amount of total losses included in income | |||||||||||||||||||
attributed to the change in unrealized gains (losses) related to assets and liabilities held for the three months ended March 31, 2014 | $ | 0 | $ | 0 | $ | -446 | $ | 0 | $ | -446 | |||||||||
(a) Includes an increase for the reclassification of $134 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three months ended March 31, 2014. | |||||||||||||||||||
Three Months Ended March 31, 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 | 1 | 0 | -127 | (a) | 0 | -126 | |||||||||||||
Included in regulatory assets | 1 | 0 | -8 | (b) | 0 | -7 | |||||||||||||
Change in collateral | 0 | 0 | 33 | 0 | 33 | ||||||||||||||
Purchases, sales, issuances and settlements | |||||||||||||||||||
Purchases | 32 | 22 | -5 | (c) | 0 | 49 | |||||||||||||
Sales | -7 | -7 | -4 | -8 | -26 | ||||||||||||||
Transfers into Level 3 | 0 | 0 | 4 | 0 | 4 | ||||||||||||||
Balance as of March 31, 2013 | $ | 210 | $ | 104 | $ | 260 | $ | 9 | $ | 583 | |||||||||
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 March 31, 2013 | $ | 1 | $ | 0 | $ | -79 | $ | 0 | $ | -78 | |||||||||
(a) Includes the reclassification of $48 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three months ended March 31, 2013. | |||||||||||||||||||
(b) Excludes increases in fair value of $8 million and realized losses reclassified due to settlements of $133 million associated with Generation's financial swap contract with ComEd for the three months ended March 31, 2013. | |||||||||||||||||||
(c) Includes $10 million which Generation was paid to enter into out of the money purchase contracts. | |||||||||||||||||||
Total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis | ' | ||||||||||||||||||
Operating Revenues | Purchased Power and Fuel | Other, net (a) | |||||||||||||||||
Total losses included in net income for the three months ended | |||||||||||||||||||
31-Mar-14 | $ | -268 | $ | -44 | $ | 1 | |||||||||||||
Change in the unrealized losses relating to assets and liabilities | |||||||||||||||||||
held for the three months ended March 31, 2014 | $ | -425 | $ | -21 | $ | 0 | |||||||||||||
Operating Revenues | Purchased Power and Fuel | Other, net (a) | |||||||||||||||||
Total gains (losses) included in net income for the three months ended | |||||||||||||||||||
31-Mar-13 | $ | -159 | $ | 32 | $ | 1 | |||||||||||||
Change in the unrealized gains (losses) relating to assets and liabilities | |||||||||||||||||||
held for the three months ended March 31, 2013 | $ | -117 | $ | 38 | $ | 1 | |||||||||||||
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 March 31, 2014 (c) | Valuation Technique | Unobservable Input | Range | |||||||||||||||
Mark-to-market derivatives – Economic Hedges (Generation) (a) | $ | 186 | Discounted Cash Flow | Forward power price | $ | 19 | - | $ | 155 | (d) | |||||||||
Forward gas price | $ | 2.18 | - | $ | 17.65 | (d) | |||||||||||||
Option Model | Volatility percentage | 14 | % | - | 207 | % | |||||||||||||
Mark-to-market derivatives – Proprietary trading (Generation) (a) | $ | -17 | Discounted Cash Flow | Forward power price | $ | 26 | - | $ | 152 | (d) | |||||||||
Option Model | Volatility percentage | 12 | % | - | 59 | % | |||||||||||||
Mark-to-market derivatives (ComEd) | $ | -168 | Discounted Cash Flow | Forward heat rate (b) | 8 | x | - | 9 | x | ||||||||||
Marketability reserve | 3.5 | % | - | 8 | % | ||||||||||||||
Renewable factor | 87 | % | - | 127 | % | ||||||||||||||
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 $118 million as of March 31, 2014. | |||||||||||||||||||
The upper ends of the ranges are driven by the winter power and gas prices in the New England region. Without the New England region, the upper ends of the ranges for power and gas would be approximately $114 and $10.62, respectively. | |||||||||||||||||||
Type of trade | Fair Value at December 31, 2013 (c) | Valuation Technique | Unobservable Input | Range | |||||||||||||||
Mark-to-market derivatives – Economic Hedges (Generation) (a) | $ | 488 | Discounted Cash Flow | Forward power price | $ | 8 | - | $ | 176 | (d) | |||||||||
Forward gas price | $ | 2.98 | - | $ | 16.63 | (d) | |||||||||||||
Option Model | Volatility percentage | 15 | % | - | 142 | % | |||||||||||||
Mark-to-market derivatives – Proprietary trading (Generation) (a) | $ | 3 | Discounted Cash Flow | Forward power price | $ | 10 | - | $ | 176 | (d) | |||||||||
Option Model | Volatility percentage | 14 | % | - | 19 | % | |||||||||||||
Mark-to-market derivatives (ComEd) | $ | -193 | Discounted Cash Flow | Forward heat rate (b) | 8 | x | - | 9 | x | ||||||||||
Marketability reserve | 3.5 | % | - | 8 | % | ||||||||||||||
Renewable factor | 84 | % | - | 128 | % | ||||||||||||||
The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions. | |||||||||||||||||||
Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract's delivery. | |||||||||||||||||||
The fair values do not include cash collateral held on level three positions of $26 million as of December 31, 2013 | |||||||||||||||||||
The upper ends of the ranges are driven by the winter power and gas prices in the New England region. Without the New England region, the upper ends of the ranges for power and gas would be approximately $100 and $5.70, respectively. | |||||||||||||||||||
Exelon Generation Co L L C [Member] | ' | ||||||||||||||||||
Fair Value Tables [Line Items] | ' | ||||||||||||||||||
Fair value of financial liabilities recorded at the carrying amount | ' | ||||||||||||||||||
31-Mar-14 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Short-term liabilities | $ | 377 | $ | 0 | $ | 377 | $ | 0 | $ | 377 | |||||||||
Long-term debt (including amounts due within one year) | 7,490 | 0 | 6,684 | 1,066 | 7,750 | ||||||||||||||
SNF obligation | 1,021 | 0 | 840 | 0 | 840 | ||||||||||||||
31-Dec-13 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Short-term liabilities | $ | 22 | $ | 0 | $ | 22 | $ | 0 | $ | 22 | |||||||||
Long-term debt (including amounts due within one year) | 7,729 | $ | 0 | 6,586 | 1,062 | 7,648 | |||||||||||||
SNF obligation | 1,021 | 0 | 790 | 0 | 790 | ||||||||||||||
Assets and liabilities measured and recorded at fair value on recurring basis | ' | ||||||||||||||||||
As of March 31, 2014 | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Assets | |||||||||||||||||||
Cash equivalents(a) | $ | 329 | $ | 0 | $ | 0 | $ | 329 | |||||||||||
Nuclear decommissioning trust fund investments | |||||||||||||||||||
Cash equivalents | 304 | 0 | 0 | 304 | |||||||||||||||
Equity | |||||||||||||||||||
Individually held | 1,813 | 0 | 0 | 1,813 | |||||||||||||||
Exchange traded funds | 113 | 0 | 0 | 113 | |||||||||||||||
Commingled funds | 0 | 2,053 | 0 | 2,053 | |||||||||||||||
Equity funds subtotal | 1,926 | 2,053 | 0 | 3,979 | |||||||||||||||
Fixed income | |||||||||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. | |||||||||||||||||||
government corporations and agencies | 903 | 0 | 0 | 903 | |||||||||||||||
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 | 87 | 0 | 87 | |||||||||||||||
Corporate debt securities | 0 | 1,795 | 126 | 1,921 | |||||||||||||||
Federal agency mortgage-backed securities | 0 | 9 | 0 | 9 | |||||||||||||||
Commercial mortgage-backed securities (non-agency) | 0 | 40 | 0 | 40 | |||||||||||||||
Residential mortgage-backed securities (non-agency) | 0 | 7 | 0 | 7 | |||||||||||||||
Mutual funds | 0 | 278 | 0 | 278 | |||||||||||||||
Fixed income subtotal | 903 | 2,511 | 126 | 3,540 | |||||||||||||||
Middle market lending | 0 | 0 | 356 | 356 | |||||||||||||||
Private Equity | 0 | 0 | 4 | 4 | |||||||||||||||
Other debt obligations | 0 | 15 | 0 | 15 | |||||||||||||||
Nuclear decommissioning trust fund investments subtotal(b) | 3,133 | 4,579 | 486 | 8,198 | |||||||||||||||
Pledged assets for Zion Station decommissioning | |||||||||||||||||||
Cash equivalents | 0 | 35 | 0 | 35 | |||||||||||||||
Equity | |||||||||||||||||||
Individually held | 4 | 1 | 0 | 5 | |||||||||||||||
Equity funds subtotal | 4 | 1 | 0 | 5 | |||||||||||||||
Fixed income | |||||||||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. | |||||||||||||||||||
government corporations and agencies | 36 | 4 | 0 | 40 | |||||||||||||||
Debt securities issued by states of the United States and | |||||||||||||||||||
political subdivisions of the states | 0 | 18 | 0 | 18 | |||||||||||||||
Corporate debt securities | 0 | 180 | 0 | 180 | |||||||||||||||
Fixed income subtotal | 36 | 202 | 0 | 238 | |||||||||||||||
Middle market lending | 0 | 0 | 137 | 137 | |||||||||||||||
Pledged assets for Zion Station decommissioning subtotal(c) | 40 | 238 | 137 | 415 | |||||||||||||||
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 | 592 | 2,778 | 1,271 | 4,641 | |||||||||||||||
Proprietary trading | 354 | 808 | 179 | 1,341 | |||||||||||||||
Effect of netting and allocation of collateral(e) | -826 | -2,957 | -911 | -4,694 | |||||||||||||||
Commodity derivative assets subtotal | 120 | 629 | 539 | 1,288 | |||||||||||||||
Interest rate and foreign currency derivative assets | 24 | 27 | 0 | 51 | |||||||||||||||
Effect of netting and allocation of collateral | -18 | -4 | 0 | -22 | |||||||||||||||
Interest rate and foreign currency derivative assets subtotal | 6 | 23 | 0 | 29 | |||||||||||||||
Other investments | 13 | 0 | 10 | 23 | |||||||||||||||
Total assets | 3,655 | 5,469 | 1,172 | 10,296 | |||||||||||||||
Liabilities | |||||||||||||||||||
Commodity derivative liabilities | |||||||||||||||||||
Economic hedges | -586 | -2,624 | -1,085 | -4,295 | |||||||||||||||
Proprietary trading | -357 | -765 | -196 | -1,318 | |||||||||||||||
Effect of netting and allocation of collateral(e) | 943 | 3,289 | 1,029 | 5,261 | |||||||||||||||
Commodity derivative liabilities subtotal | 0 | -100 | -252 | -352 | |||||||||||||||
Interest rate and foreign currency derivative liabilities | -25 | -20 | 0 | -45 | |||||||||||||||
Effect of netting and allocation of collateral | 25 | 3 | 0 | 28 | |||||||||||||||
Interest rate and foreign currency derivative liabilities subtotal | 0 | -17 | 0 | -17 | |||||||||||||||
Deferred compensation obligation | 0 | -29 | 0 | -29 | |||||||||||||||
Total liabilities | 0 | -146 | -252 | -398 | |||||||||||||||
Total net assets | $ | 3,655 | $ | 5,323 | $ | 920 | $ | 9,898 | |||||||||||
As of December 31, 2013 | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Assets | |||||||||||||||||||
Cash equivalents(a) | $ | 1,006 | $ | 0 | $ | 0 | $ | 1,006 | |||||||||||
Nuclear decommissioning trust fund investments | |||||||||||||||||||
Cash equivalents | 459 | 0 | 0 | 459 | |||||||||||||||
Equity | |||||||||||||||||||
Individually held | 1,776 | 0 | 0 | 1,776 | |||||||||||||||
Exchange traded funds | 115 | 0 | 0 | 115 | |||||||||||||||
Commingled funds | 0 | 2,271 | 0 | 2,271 | |||||||||||||||
Equity funds subtotal | 1,891 | 2,271 | 0 | 4,162 | |||||||||||||||
Fixed income | |||||||||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. | |||||||||||||||||||
government corporations and agencies | 882 | 0 | 0 | 882 | |||||||||||||||
Debt securities issued by states of the United States and | |||||||||||||||||||
political subdivisions of the states | 0 | 294 | 0 | 294 | |||||||||||||||
Debt securities issued by foreign governments | 0 | 87 | 0 | 87 | |||||||||||||||
Corporate debt securities | 0 | 1,753 | 31 | 1,784 | |||||||||||||||
Federal agency mortgage-backed securities | 0 | 10 | 0 | 10 | |||||||||||||||
Commercial mortgage-backed securities (non-agency) | 0 | 40 | 0 | 40 | |||||||||||||||
Residential mortgage-backed securities (non-agency) | 0 | 7 | 0 | 7 | |||||||||||||||
Mutual funds | 0 | 18 | 0 | 18 | |||||||||||||||
Fixed income subtotal | 882 | 2,209 | 31 | 3,122 | |||||||||||||||
Middle market lending | 0 | 0 | 314 | 314 | |||||||||||||||
Private Equity | 0 | 0 | 5 | 5 | |||||||||||||||
Other debt obligations | 0 | 14 | 0 | 14 | |||||||||||||||
Nuclear decommissioning trust fund investments subtotal(b) | 3,232 | 4,494 | 350 | 8,076 | |||||||||||||||
Pledged assets for Zion Station decommissioning | |||||||||||||||||||
Cash equivalents | 0 | 26 | 0 | 26 | |||||||||||||||
Equity | |||||||||||||||||||
Individually held | 16 | 0 | 0 | 16 | |||||||||||||||
Equity funds subtotal | 16 | 0 | 0 | 16 | |||||||||||||||
Fixed income | |||||||||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. | |||||||||||||||||||
government corporations and agencies | 45 | 4 | 0 | 49 | |||||||||||||||
Debt securities issued by states of the United States and | |||||||||||||||||||
political subdivisions of the states | 0 | 20 | 0 | 20 | |||||||||||||||
Corporate debt securities | 0 | 227 | 0 | 227 | |||||||||||||||
Fixed income subtotal | 45 | 251 | 0 | 296 | |||||||||||||||
Middle market lending | 0 | 0 | 112 | 112 | |||||||||||||||
Other debt obligations | 0 | 1 | 0 | 1 | |||||||||||||||
Pledged assets for Zion Station decommissioning subtotal(c) | 61 | 278 | 112 | 451 | |||||||||||||||
Rabbi trust investments | |||||||||||||||||||
Mutual funds(d) | 13 | 0 | 0 | 13 | |||||||||||||||
Rabbi trust investments subtotal | 13 | 0 | 0 | 13 | |||||||||||||||
Commodity derivative assets | |||||||||||||||||||
Economic hedges | 493 | 2,582 | 885 | 3,960 | |||||||||||||||
Proprietary trading | 324 | 1,315 | 122 | 1,761 | |||||||||||||||
Effect of netting and allocation of collateral(e) | -863 | -3,131 | -430 | -4,424 | |||||||||||||||
Commodity and foreign currency assets subtotal | -46 | 766 | 577 | 1,297 | |||||||||||||||
Interest rate and foreign currency derivative assets | 30 | 32 | 0 | 62 | |||||||||||||||
Effect of netting and allocation of collateral | -30 | -2 | 0 | -32 | |||||||||||||||
Interest rate and foreign currency derivative assets subtotal | 0 | 30 | 0 | 30 | |||||||||||||||
Other investments | 0 | 0 | 15 | 15 | |||||||||||||||
Total assets | 4,266 | 5,568 | 1,054 | 10,888 | |||||||||||||||
Liabilities | |||||||||||||||||||
Commodity derivative liabilities | |||||||||||||||||||
Economic hedges | -540 | -1,890 | -397 | -2,827 | |||||||||||||||
Proprietary trading | -328 | -1,256 | -119 | -1,703 | |||||||||||||||
Effect of netting and allocation of collateral(e) | 869 | 3,007 | 404 | 4,280 | |||||||||||||||
Commodity derivative liabilities subtotal | 1 | -139 | -112 | -250 | |||||||||||||||
Interest rate derivative liabilities | -31 | -13 | 0 | -44 | |||||||||||||||
Effect of netting and allocation of collateral | 31 | 1 | 0 | 32 | |||||||||||||||
Interest rate and foreign currency derivative liabilities | 0 | -12 | 0 | -12 | |||||||||||||||
Deferred compensation obligation | 0 | -29 | 0 | -29 | |||||||||||||||
Total liabilities | 1 | -180 | -112 | -291 | |||||||||||||||
Total net assets | $ | 4,267 | $ | 5,388 | $ | 942 | $ | 10,597 | |||||||||||
Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis | ' | ||||||||||||||||||
Three Months Ended March 31, 2014 | Nuclear Decommissioning Trust Fund Investments | Pledged Assets for Zion Station Decommissioning | Mark-to-Market Derivatives | Other Investments | Total | ||||||||||||||
Balance as of December 31, 2013 | $ | 350 | $ | 112 | $ | 465 | $ | 15 | $ | 942 | |||||||||
Total realized / unrealized losses | |||||||||||||||||||
Included in net income | 1 | 0 | -312 | (a) | 0 | -311 | |||||||||||||
Included in noncurrent payables to affiliates | 3 | 0 | 0 | 0 | 3 | ||||||||||||||
Included in payable for Zion Station decommissioning | 0 | -1 | 0 | 0 | -1 | ||||||||||||||
Change in collateral | 0 | 0 | 144 | 0 | 144 | ||||||||||||||
Purchases, sales, issuances and settlements | |||||||||||||||||||
Purchases | 139 | 30 | 10 | 2 | 181 | ||||||||||||||
Sales | -1 | -4 | -2 | 0 | -7 | ||||||||||||||
Settlements | -6 | 0 | 0 | 0 | -6 | ||||||||||||||
Transfers into Level 3 | 0 | 0 | -26 | 0 | -26 | ||||||||||||||
Transfers out of Level 3 | 0 | 0 | 8 | -7 | 1 | ||||||||||||||
Balance as of March 31, 2014 | $ | 486 | $ | 137 | $ | 287 | $ | 10 | $ | 920 | |||||||||
The amount of total losses included in income | |||||||||||||||||||
attributed to the change in unrealized gains (losses) related to assets and liabilities held for the three months ended March 31, 2014 | $ | 0 | $ | 0 | $ | -446 | $ | 0 | $ | -446 | |||||||||
(a) Includes an increase for the reclassification of $134 million of realized losses due to the settlement of derivative contracts recorded in results of operations. | |||||||||||||||||||
Three Months Ended March 31, 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 losses | |||||||||||||||||||
Included in net income | 1 | 0 | -144 | (a)(b) | 0 | -143 | |||||||||||||
Included in other comprehensive income | 0 | 0 | -124 | (b) | 0 | -124 | |||||||||||||
Included in noncurrent payables to affiliates | 1 | 0 | 0 | 0 | 1 | ||||||||||||||
Change in collateral | 0 | 0 | 33 | 0 | 33 | ||||||||||||||
Purchases, sales, issuances and settlements | |||||||||||||||||||
Purchases | 32 | 22 | -5 | (c) | 0 | 49 | |||||||||||||
Sales | -7 | -7 | -4 | -8 | -26 | ||||||||||||||
Transfers into Level 3 | 0 | 0 | 4 | 0 | 4 | ||||||||||||||
Balance as of March 31, 2013 | $ | 210 | $ | 104 | $ | 420 | $ | 9 | $ | 743 | |||||||||
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 March 31, 2013 | |||||||||||||||||||
$ | 1 | $ | 0 | $ | -86 | $ | 0 | $ | -85 | ||||||||||
(a) Includes the reclassification of $58 million of realized losses due to the settlement of derivative contracts recorded in results of operations. | |||||||||||||||||||
(b) Includes $8 million of increases in fair value and $133 million of realized losses due to settlements during 2013 of Generation's financial swap contract with ComEd, which eliminates upon consolidation in Exelon's Consolidated Financial Statements. | |||||||||||||||||||
(c) Includes $10 million which Generation was paid to enter into out of the money purchase contracts. | |||||||||||||||||||
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 Revenues | Purchased Power and Fuel | Other, net(a) | |||||||||||||||||
Total losses included in net income for the three | |||||||||||||||||||
months ended March 31, 2014 | $ | -268 | $ | -44 | $ | 1 | |||||||||||||
Change in the unrealized losses relating to assets and | |||||||||||||||||||
liabilities held for the three months ended March 31, 2014 | $ | -425 | $ | -21 | $ | 0 | |||||||||||||
Operating Revenues | Purchased Power and Fuel | Other, net(a) | |||||||||||||||||
Total gains (losses) included in net income for the three months | |||||||||||||||||||
ended March 31, 2013 | $ | -176 | $ | 32 | $ | 1 | |||||||||||||
Change in the unrealized gains (losses) relating to assets and | |||||||||||||||||||
liabilities held for the three months ended March 31, 2013 | $ | -124 | $ | 38 | $ | 1 | |||||||||||||
(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 | ' | ||||||||||||||||||
31-Mar-14 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Short-term liabilities | $ | 534 | $ | 0 | $ | 534 | $ | 0 | $ | 534 | |||||||||
Long-term debt (including amounts due within one year) | 5,707 | 0 | 6,347 | 0 | 6,347 | ||||||||||||||
Long-term debt to financing trust | 206 | 0 | 0 | 202 | 202 | ||||||||||||||
31-Dec-13 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Short-term liabilities | $ | 184 | $ | 0 | $ | 184 | $ | 0 | $ | 184 | |||||||||
Long-term debt (including amounts due within one year) | 5,675 | 0 | 6,238 | 17 | 6,255 | ||||||||||||||
Long-term debt to financing trust | 206 | 0 | 0 | 202 | 202 | ||||||||||||||
Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis | ' | ||||||||||||||||||
Three Months Ended March 31, 2014 | Mark-to-Market Derivatives | ||||||||||||||||||
Balance as of December 31, 2013 | $ | -193 | |||||||||||||||||
Total realized / unrealized gains included in regulatory assets(a) | 25 | ||||||||||||||||||
Balance as of March 31, 2014 | $ | -168 | |||||||||||||||||
(a) Includes $30 million of decrease in the fair value partially offset by realized gains due to settlements of $5 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended March 31, 2014. | |||||||||||||||||||
Three Months Ended March 31, 2013 | Mark-to-Market Derivatives | ||||||||||||||||||
Balance as of December 31, 2012 | $ | -293 | |||||||||||||||||
Total unrealized / realized gains included in regulatory assets(a)(b) | 133 | ||||||||||||||||||
Balance as of March 31, 2013 | $ | -160 | |||||||||||||||||
Includes $8 million of decreases in fair value and $133 million of realized gains due to settlements associated with ComEd's financial swap with Generation. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements. | |||||||||||||||||||
Includes $11 million of increases in fair value and realized losses due to settlements of $3 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three ended March 31, 2013. | |||||||||||||||||||
PECO Energy Co [Member] | ' | ||||||||||||||||||
Fair Value Tables [Line Items] | ' | ||||||||||||||||||
Fair value of financial liabilities recorded at the carrying amount | ' | ||||||||||||||||||
31-Mar-14 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Long-term debt (including amounts due within one year) | $ | 2,197 | $ | 0 | $ | 2,392 | $ | 0 | $ | 2,392 | |||||||||
Long-term debt to financing trusts | 184 | 0 | 0 | 190 | 190 | ||||||||||||||
31-Dec-13 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Long-term debt (including amounts due within one year) | 2,197 | 0 | 2,358 | 0 | 2,358 | ||||||||||||||
Long-term debt to financing trusts | 184 | 0 | 0 | 180 | 180 | ||||||||||||||
Baltimore Gas and Electric Company [Member] | ' | ||||||||||||||||||
Fair Value Tables [Line Items] | ' | ||||||||||||||||||
Fair value of financial liabilities recorded at the carrying amount | ' | ||||||||||||||||||
31-Mar-14 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Short-term liabilities | $ | 72 | $ | 3 | $ | 69 | $ | 0 | $ | 72 | |||||||||
Long-term debt (including amounts due within one year) | 2,011 | 0 | 2,183 | 0 | 2,183 | ||||||||||||||
Long-term debt to financing trusts | 258 | 0 | 0 | 256 | 256 | ||||||||||||||
31-Dec-13 | |||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Short-term liabilities | $ | 138 | $ | 3 | $ | 135 | $ | 0 | $ | 138 | |||||||||
Long-term debt (including amounts due within one year) | 2,011 | 0 | 2,148 | 0 | 2,148 | ||||||||||||||
Long-term debt to financing trusts | 258 | 0 | 0 | 249 | 249 |
Derivative_Financial_Instrumen1
Derivative Financial Instruments (Tables) | 3 Months Ended | |||||||||||||||
Mar. 31, 2014 | ||||||||||||||||
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 | ' | |||||||||||||||
__________ | ||||||||||||||||
For the three months ended March 31, 2014 and 2013, the loss on Generation swaps included $4 million and $4 million realized in earnings, respectively, 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) | $ | 0 | $ | 4 | $ | 12 | $ | -14 | $ | 2 | $ | 0 | $ | 2 | ||
Mark-to-market derivative assets | ||||||||||||||||
(noncurrent assets) | 20 | 2 | 13 | -8 | 27 | 10 | 37 | |||||||||
Total mark-to-market derivative assets | $ | 20 | $ | 6 | $ | 25 | $ | -22 | $ | 29 | $ | 10 | $ | 39 | ||
Mark-to-market derivative liabilities | ||||||||||||||||
(current liabilities) | $ | -1 | $ | -3 | $ | -15 | $ | 17 | $ | -2 | $ | 0 | $ | -2 | ||
Mark-to-market derivative liabilities | ||||||||||||||||
(noncurrent liabilities) | -15 | -1 | -10 | 11 | -15 | -1 | -16 | |||||||||
Total mark-to-market derivative liabilities | $ | -16 | $ | -4 | $ | -25 | $ | 28 | $ | -17 | $ | -1 | $ | -18 | ||
Total mark-to-market derivative | ||||||||||||||||
net assets (liabilities) | $ | 4 | $ | 2 | $ | 0 | $ | 6 | $ | 12 | $ | 9 | $ | 21 | ||
Generation enters into interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The characterization of the interest rate derivative contracts between the proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rate exposure. Generation does not utilize proprietary trading interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates. | ||||||||||||||||
Represents the netting of fair value balances with the same counterparty and any associated cash collateral. | ||||||||||||||||
Generation | Other | Exelon | ||||||||||||||
Description | Derivatives Designated as Hedging Instruments | Economic Hedges | Proprietary Trading (a) | Collateral and Netting(b) | Subtotal | Derivatives Designated as Hedging Instruments | Total | |||||||||
Mark-to-market derivative assets | ||||||||||||||||
(current assets) | $ | 0 | $ | 3 | $ | 15 | $ | -19 | $ | -1 | $ | 0 | $ | -1 | ||
Mark-to-market derivative assets | ||||||||||||||||
(noncurrent assets) | 26 | 3 | 15 | -13 | 31 | 7 | 38 | |||||||||
Total mark-to-market derivative assets | $ | 26 | $ | 6 | $ | 30 | $ | -32 | $ | 30 | $ | 7 | $ | 37 | ||
Mark-to-market derivative liabilities | ||||||||||||||||
(current liabilities) | $ | -1 | $ | -1 | $ | -18 | $ | 19 | $ | -1 | $ | 0 | $ | -1 | ||
Mark-to-market derivative liabilities | ||||||||||||||||
(noncurrent liabilities) | -10 | -1 | -13 | 13 | -11 | -4 | -15 | |||||||||
Total mark-to-market derivative liabilities | $ | -11 | $ | -2 | $ | -31 | $ | 32 | $ | -12 | $ | -4 | $ | -16 | ||
Total mark-to-market derivative | ||||||||||||||||
net assets (liabilities) | $ | 15 | $ | 4 | $ | -1 | $ | 0 | $ | 18 | $ | 3 | $ | 21 | ||
Generation enters into interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The characterization of the interest rate derivative contracts between the proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rate exposure. Generation does not utilize proprietary trading interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates. | ||||||||||||||||
Represents the netting of fair value balances with the same counterparty and any associated cash collateral. | ||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||
Income Statement | 2014 | 2013 | 2014 | 2013 | ||||||||||||
Location | Gain (Loss) on Swaps | Gain (Loss) on Borrowings | ||||||||||||||
Generation | Interest expense(a) | $ | -5 | $ | -4 | $ | -1 | $ | -1 | |||||||
Exelon | Interest expense | $ | 2 | $ | -6 | $ | 4 | $ | 1 | |||||||
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) | $ | 3,401 | $ | 1,146 | $ | -3,793 | $ | 754 | $ | 0 | $ | 754 | ||||
Mark-to-market derivative assets | ||||||||||||||||
(noncurrent assets) | 1,240 | 195 | -901 | 534 | 0 | 534 | ||||||||||
Total mark-to-market derivative | ||||||||||||||||
assets | $ | 4,641 | $ | 1,341 | $ | -4,694 | $ | 1,288 | $ | 0 | $ | 1,288 | ||||
Mark-to-market derivative liabilities | ||||||||||||||||
(current liabilities) | $ | -3,348 | $ | -1,112 | $ | 4,224 | $ | -236 | $ | -13 | $ | -249 | ||||
Mark-to-market derivative liabilities | ||||||||||||||||
(noncurrent liabilities) | -947 | -206 | 1,037 | -116 | -155 | -271 | ||||||||||
Total mark-to-market derivative | ||||||||||||||||
liabilities | $ | -4,295 | $ | -1,318 | $ | 5,261 | $ | -352 | $ | -168 | $ | -520 | ||||
Total mark-to-market derivative | ||||||||||||||||
net assets (liabilities) | $ | 346 | $ | 23 | $ | 567 | $ | 936 | $ | -168 | $ | 768 | ||||
__________ | ||||||||||||||||
(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 $(179) million and $(36) million, respectively, and current and noncurrent liabilities are shown net of collateral of $(252) million and $(100) million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $567 million at March 31, 2014. | ||||||||||||||||
(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 | Total | ||||||||||||
Description | Hedges | Trading | Netting(a) | Subtotal(b) | Hedges (c) | Derivatives | ||||||||||
Mark-to-market derivative assets | ||||||||||||||||
(current assets) | $ | 2,616 | $ | 1,476 | $ | -3,364 | $ | 728 | $ | 0 | $ | 728 | ||||
Mark-to-market derivative assets | ||||||||||||||||
(noncurrent assets) | 1,344 | 285 | -1,060 | 569 | 0 | 569 | ||||||||||
Total mark-to-market derivative | ||||||||||||||||
assets | $ | 3,960 | $ | 1,761 | $ | -4,424 | $ | 1,297 | $ | 0 | $ | 1,297 | ||||
Mark-to-market derivative liabilities | ||||||||||||||||
(current liabilities) | $ | -2,023 | $ | -1,410 | $ | 3,292 | $ | -141 | $ | -17 | $ | -158 | ||||
Mark-to-market derivative liabilities | ||||||||||||||||
(noncurrent liabilities) | -804 | -293 | 988 | -109 | -176 | -285 | ||||||||||
Total mark-to-market derivative | ||||||||||||||||
liabilities | $ | -2,827 | $ | -1,703 | $ | 4,280 | $ | -250 | $ | -193 | $ | -443 | ||||
Total mark-to-market derivative | ||||||||||||||||
net assets (liabilities) | $ | 1,133 | $ | 58 | $ | -144 | $ | 1,047 | $ | -193 | $ | 854 | ||||
__________ | ||||||||||||||||
(a) Exelon and Generation net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, and letters of credit. These are not reflected in the table above. | ||||||||||||||||
(b) Current and noncurrent assets are shown net of collateral of $84 million and $72 million, respectively, and current and noncurrent liabilities are shown net of collateral of $(12) million and $0 million, respectively. The total cash collateral received, net of cash collateral posted and offset against mark-to-market assets and liabilities was $144 million at December 31, 2013. | ||||||||||||||||
(c) Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers. | ||||||||||||||||
Other Derivatives - Gain (loss) and reclassification | ' | |||||||||||||||
Generation | Intercompany Eliminations | Exelon | ||||||||||||||
Purchased | ||||||||||||||||
Operating | Power | Operating | ||||||||||||||
Three Months Ended March 31, 2014 | Revenues | and Fuel | Total | Revenues | Total | |||||||||||
Change in fair value | $ | -853 | $ | 171 | $ | -682 | $ | 0 | $ | -682 | ||||||
Reclassification to realized at | ||||||||||||||||
settlement | 93 | -141 | -48 | 0 | -48 | |||||||||||
Net mark-to-market gains | ||||||||||||||||
(losses) | $ | -760 | $ | 30 | $ | -730 | $ | 0 | $ | -730 | ||||||
Exelon and Generation | Intercompany Eliminations | Exelon | ||||||||||||||
Purchased | ||||||||||||||||
Operating | Power | Operating | ||||||||||||||
Three Months Ended March 31, 2013 | Revenues | and Fuel | Total | Revenues (a) | Total | |||||||||||
Change in fair value | $ | -485 | $ | 149 | $ | -336 | $ | 7 | $ | -329 | ||||||
Reclassification to realized at | ||||||||||||||||
settlement | -101 | 34 | -67 | 10 | -57 | |||||||||||
Net mark-to-market gains | ||||||||||||||||
(losses) | $ | -586 | $ | 183 | $ | -403 | $ | 17 | $ | -386 | ||||||
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 were recorded to operating revenues and eliminated in consolidation. | ||||||||||||||||
Three Months Ended | ||||||||||||||||
Location on Income | March 31, | |||||||||||||||
Statement | 2014 | 2013 | ||||||||||||||
Change in fair value | Operating Revenues | $ | -3 | $ | -4 | |||||||||||
Reclassification to realized at settlement | Operating Revenues | 1 | 6 | |||||||||||||
Net mark-to-market gains (losses) | Operating Revenues | $ | -2 | $ | 2 | |||||||||||
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 March 31, 2014 | Collateral | Collateral(a) | Exposure | of Net Exposure | of Net Exposure | |||||||||||
Investment grade | $ | 1,182 | $ | 117 | $ | 1,065 | 1 | $ | 443 | |||||||
Non-investment grade | 35 | 22 | 13 | 0 | 0 | |||||||||||
No external ratings | ||||||||||||||||
Internally rated - investment grade | 321 | 0 | 321 | 1 | 206 | |||||||||||
Internally rated - non-investment | ||||||||||||||||
grade | 32 | 9 | 23 | 0 | 0 | |||||||||||
Total | $ | 1,570 | $ | 148 | $ | 1,422 | 2 | $ | 649 | |||||||
Net Credit Exposure by Type of Counterparty | As of March 31, 2014 | |||||||||||||||
Financial institutions | $ | 201 | ||||||||||||||
Investor-owned utilities, marketers, power producers | 392 | |||||||||||||||
Energy cooperatives and municipalities | 799 | |||||||||||||||
Other | 30 | |||||||||||||||
Total | $ | 1,422 | ||||||||||||||
Credit-Risk Related Contingent Feature | March 31, | December 31, | ||||||||||||||
2014 | 2013 | |||||||||||||||
Gross Fair Value of Derivative Contracts Containing this Feature(a) | $ | -1,178 | $ | -1,056 | ||||||||||||
Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements(b) | 902 | 846 | ||||||||||||||
Net Fair Value of Derivative Contracts Containing This Feature(c) | $ | -276 | $ | -210 | ||||||||||||
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) | 3 Months Ended | ||||||||||
Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2013 | |||||||||
Commonwealth Edison Co [Member] | Baltimore Gas and Electric Company [Member] | ||||||||||
Debt Instrument [Line Items] | ' | ' | ' | ||||||||
Schedule Of Short Term Debt [Text Block] | ' | '184 | '135 | ||||||||
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-19 | 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 March 31, 2014, letters of credit issued under these agreements for Generation, ComEd, PECO and BGE totaled $20 million, $17 million, $21 million and $1 million, respectively. | |||||||||||
Debt_and_Credit_Agreements_Qua
Debt and Credit Agreements Quarter-End (Tables) | 3 Months Ended | ||||||||||||
Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2013 | |||||||||||
Commonwealth Edison Co [Member] | Baltimore Gas and Electric Company [Member] | ||||||||||||
Debt and Credit Agreements [Line Items] | ' | ' | ' | ||||||||||
Commercial paper and credit facility borrowings outstanding | ' | '184 | '135 | ||||||||||
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-19 | 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 March 31, 2014, letters of credit issued under these agreements for Generation, ComEd, PECO and BGE totaled $20 million, $17 million, $21 million and $1 million, respectively. | |||||||||||||
Issuance of Long-Term Debt | ' | ' | ' | ||||||||||
Company | Type | Interest Rate | Maturity | Amount | Use of Proceeds | ||||||||
Generation | ExGen Renewables I Project Financing | LIBOR + 4.250% | 6-Feb-21 | $ | 300 | Used for general corporate purposes | |||||||
ComEd | Mortgage Bonds Series 115 | 2.15 | % | 15-Jan-19 | $ | 300 | Used to refinance existing mortgage bonds | ||||||
ComEd | Mortgage Bonds Series 116 | 4.7 | % | 15-Jan-44 | $ | 350 | Used to refinance existing mortgage bonds | ||||||
Company | Type | Interest Rate | Maturity | Amount | Use of Proceeds | ||||||||
Generation | Upstream Gas Lending Agreement | 2.21 | % | 22-Jul-16 | $ | 3 | Used to fund Upstream gas activities | ||||||
Generation | DOE Project Financing | 2.720 - 2.810 | % | 5-Jan-37 | $ | 146 | Funding for Antelope Valley Solar Development | ||||||
Retirement of Long-Term Debt | ' | ' | ' | ||||||||||
Company | Type | Interest Rate | Maturity | Amount | |||||||||
Generation | 2003 Senior Notes | 5.35 | % | 15-Jan-14 | $ | 500 | |||||||
Generation | Pollution Control Loan | 4.1 | % | 1-Jul-14 | $ | 20 | |||||||
Generation | Continental Wind Project Financing | 6 | % | 28-Feb-33 | $ | 11 | |||||||
Generation | Kennett Square Capital Lease | 7.83 | % | 20-Sep-20 | $ | 1 | |||||||
ComEd | Mortgage Bonds Series 110 | 1.63 | % | 15-Jan-14 | $ | 600 | |||||||
ComEd | Pollution Control Series 1994C | 5.85 | % | 15-Jan-14 | $ | 17 | |||||||
Company | Type | Interest Rate | Maturity | Amount | |||||||||
Generation | Kennett Square Capital Lease | 7.83 | % | 20-Sep-20 | $ | 1 |
Income_Taxes_Tables
Income Taxes (Tables) | 3 Months Ended | |||||||||||||||
Mar. 31, 2014 | ||||||||||||||||
Income Taxes [Line Items] | ' | |||||||||||||||
Effective Income Tax Rate Reconciliation | ' | |||||||||||||||
For the Three Months Ended March 31, 2014 | Exelon | Generation (a) | 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 | -57.6 | 9.7 | 5.5 | 1.2 | 5.2 | |||||||||||
Qualified nuclear decommissioning trust fund income | 44.2 | -4.6 | — | — | — | |||||||||||
Domestic production activities deduction | -27.8 | 2.9 | — | — | — | |||||||||||
Health care reform legislation | 1.3 | — | 0.1 | — | 0.2 | |||||||||||
Amortization of investment tax credit, net | ||||||||||||||||
deferred taxes | -18 | 1.7 | -0.3 | -0.1 | -0.2 | |||||||||||
Plant basis differences | -31.4 | — | -0.6 | -8.7 | -0.6 | |||||||||||
Production tax credits and other credits | -36.5 | 3.8 | — | — | — | |||||||||||
Other | -47.7 | 3.3 | 0.2 | 0.2 | 0.1 | |||||||||||
Effective income tax rate | -138.5 | % | 51.8 | % | 39.9 | % | 27.6 | % | 39.7 | % | ||||||
For the Three Months Ended March 31, 2013 | Exelon | Generation (b) | ComEd (b) | 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 | 68 | 82 | 5.8 | 2.8 | 5.7 | |||||||||||
Qualified nuclear decommissioning trust fund income | 62 | -192.3 | — | — | — | |||||||||||
Domestic production activities deduction | -2.4 | 7.4 | — | — | — | |||||||||||
Tax exempt income | -1.6 | 4.8 | — | — | — | |||||||||||
Health care reform legislation | 2.2 | — | -0.5 | — | 0.4 | |||||||||||
Amortization of investment tax credit, net | ||||||||||||||||
deferred taxes | -25.8 | 75.6 | 0.4 | -0.1 | -0.2 | |||||||||||
Plant basis differences | -24.9 | — | 0.9 | -6.7 | -0.6 | |||||||||||
Production tax credits and other credits | -21.7 | 67.2 | — | — | — | |||||||||||
Other | 7.4 | -74.1 | 0.1 | 0.1 | 0.4 | |||||||||||
Effective income tax rate | 98.2 | % | 5.6 | % | 41.7 | % | 31.1 | % | 40.7 | % |
Asset_Retirement_Obligations_T
Asset Retirement Obligations (Tables) | 3 Months Ended | ||||||
Mar. 31, 2014 | |||||||
Asset Retirement Obligations Tables [Line Items] | ' | ||||||
Nuclear decommissioning asset retirement obligation rollforward | ' | ||||||
Nuclear decommissioning ARO at December 31, 2013 (a) | $ | 4,855 | |||||
Accretion expense(a) | 66 | ||||||
Costs incurred to decommission retired plants | -1 | ||||||
Nuclear decommissioning ARO at March 31, 2014 (a) | $ | 4,920 | |||||
(a) Includes $9 million as the current portion of the ARO at March 31, 2014 and December 31, 2013 which is included in Other current liabilities on Exelon's and Generation's Consolidated Balance Sheets. | |||||||
Unrealized Gains (Losses) on nuclear decommissioning trust funds | ' | ||||||
Three Months Ended | |||||||
March 31, | |||||||
2014 | 2013 | ||||||
Net unrealized gains on decommissioning trust funds — | |||||||
Regulatory Agreement Units (a) | $ | 61 | $ | 195 | |||
Net unrealized gains on decommissioning trust funds — | |||||||
Non-Regulatory Agreement Units (b)(c) | 13 | 64 | |||||
(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 $ 10 million and $2 million of net unrealized gains related to the Zion Station pledged assets for the three months ended March 31, 2014 and 2013, 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 with Non-Regulatory Agreement Units are included within Other, net in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. | |||||||
Zion Station pledged assets | ' | ||||||
Exelon and Generation | |||||||
March 31, | December 31, | ||||||
2014 | 2013 | ||||||
Carrying value of Zion Station pledged assets | $ | 429 | $ | 458 | |||
Payable to Zion Solutions (a) | 385 | 414 | |||||
Current portion of payable to Zion Solutions (b) | 103 | 109 | |||||
Withdrawals by Zion Solutions to pay decommissioning costs (c) | 537 | 498 | |||||
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, 2013 (a) | $ | 4,855 | |||||
Accretion expense(a) | 66 | ||||||
Costs incurred to decommission retired plants | -1 | ||||||
Nuclear decommissioning ARO at March 31, 2014 (a) | $ | 4,920 | |||||
Unrealized Gains (Losses) on nuclear decommissioning trust funds | ' | ||||||
Three Months Ended | |||||||
March 31, | |||||||
2014 | 2013 | ||||||
Net unrealized gains on decommissioning trust funds — | |||||||
Regulatory Agreement Units (a) | $ | 61 | $ | 195 | |||
Net unrealized gains on decommissioning trust funds — | |||||||
Non-Regulatory Agreement Units (b)(c) | 13 | 64 | |||||
Zion Station pledged assets | ' | ||||||
Exelon and Generation | |||||||
March 31, | December 31, | ||||||
2014 | 2013 | ||||||
Carrying value of Zion Station pledged assets | $ | 429 | $ | 458 | |||
Payable to Zion Solutions (a) | 385 | 414 | |||||
Current portion of payable to Zion Solutions (b) | 103 | 109 | |||||
Withdrawals by Zion Solutions to pay decommissioning costs (c) | 537 | 498 | |||||
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) | 3 Months Ended | ||||||
Mar. 31, 2014 | |||||||
Schedule Of Nuclear Decommissioning [Line Items] | ' | ||||||
Nuclear decommissioning asset retirement obligation rollforward | ' | ||||||
Nuclear decommissioning ARO at December 31, 2013 (a) | $ | 4,855 | |||||
Accretion expense(a) | 66 | ||||||
Costs incurred to decommission retired plants | -1 | ||||||
Nuclear decommissioning ARO at March 31, 2014 (a) | $ | 4,920 | |||||
(a) Includes $9 million as the current portion of the ARO at March 31, 2014 and December 31, 2013 which is included in Other current liabilities on Exelon's and Generation's Consolidated Balance Sheets. | |||||||
Unrealized Gains (Losses) on nuclear decommissioning trust funds | ' | ||||||
Three Months Ended | |||||||
March 31, | |||||||
2014 | 2013 | ||||||
Net unrealized gains on decommissioning trust funds — | |||||||
Regulatory Agreement Units (a) | $ | 61 | $ | 195 | |||
Net unrealized gains on decommissioning trust funds — | |||||||
Non-Regulatory Agreement Units (b)(c) | 13 | 64 | |||||
(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 $ 10 million and $2 million of net unrealized gains related to the Zion Station pledged assets for the three months ended March 31, 2014 and 2013, 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 with Non-Regulatory Agreement Units are included within Other, net in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. | |||||||
Zion Station pledged assets | ' | ||||||
Exelon and Generation | |||||||
March 31, | December 31, | ||||||
2014 | 2013 | ||||||
Carrying value of Zion Station pledged assets | $ | 429 | $ | 458 | |||
Payable to Zion Solutions (a) | 385 | 414 | |||||
Current portion of payable to Zion Solutions (b) | 103 | 109 | |||||
Withdrawals by Zion Solutions to pay decommissioning costs (c) | 537 | 498 | |||||
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, 2013 (a) | $ | 4,855 | |||||
Accretion expense(a) | 66 | ||||||
Costs incurred to decommission retired plants | -1 | ||||||
Nuclear decommissioning ARO at March 31, 2014 (a) | $ | 4,920 | |||||
Unrealized Gains (Losses) on nuclear decommissioning trust funds | ' | ||||||
Three Months Ended | |||||||
March 31, | |||||||
2014 | 2013 | ||||||
Net unrealized gains on decommissioning trust funds — | |||||||
Regulatory Agreement Units (a) | $ | 61 | $ | 195 | |||
Net unrealized gains on decommissioning trust funds — | |||||||
Non-Regulatory Agreement Units (b)(c) | 13 | 64 | |||||
Zion Station pledged assets | ' | ||||||
Exelon and Generation | |||||||
March 31, | December 31, | ||||||
2014 | 2013 | ||||||
Carrying value of Zion Station pledged assets | $ | 429 | $ | 458 | |||
Payable to Zion Solutions (a) | 385 | 414 | |||||
Current portion of payable to Zion Solutions (b) | 103 | 109 | |||||
Withdrawals by Zion Solutions to pay decommissioning costs (c) | 537 | 498 | |||||
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) | 3 Months Ended | ||||||||||||
Mar. 31, 2014 | |||||||||||||
Retirement Benefits [Line Items] | ' | ||||||||||||
Schedule of Defined Benefit Plans Disclosures [Text Block] | ' | ||||||||||||
Other | |||||||||||||
Pension Benefits | Postretirement Benefits | ||||||||||||
Three Months Ended | Three Months Ended | ||||||||||||
March 31, | March 31, | ||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||
Service cost | $ | 69 | $ | 80 | $ | 33 | $ | 41 | |||||
Interest cost | 183 | 163 | 55 | 48 | |||||||||
Expected return on assets | -241 | -253 | -38 | -33 | |||||||||
Amortization of: | |||||||||||||
Prior service cost (benefit) | 3 | 3 | -4 | -4 | |||||||||
Actuarial loss | 105 | 140 | 8 | 20 | |||||||||
Net periodic benefit cost | $ | 119 | $ | 133 | $ | 54 | $ | 72 | |||||
Schedule Of Pension And Other Postretirement Benefit Costs [Text Block] | ' | ||||||||||||
Three Months Ended March 31, | |||||||||||||
Pension and Other Postretirement Benefit Costs | 2014 | 2013 | |||||||||||
Generation | $ | 75 | $ | 87 | |||||||||
ComEd | 56 | 77 | |||||||||||
PECO | 12 | 11 | |||||||||||
BGE | 16 | 13 | |||||||||||
BSC(a) | 14 | 17 | |||||||||||
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. | |||||||||||||
Schedule Of Defined Contributions [Text Block] | ' | ||||||||||||
Three Months Ended March 31, | |||||||||||||
Savings Plan Matching Contributions | 2014 | 2013 | |||||||||||
Exelon | $ | 29 | $ | 22 | |||||||||
Generation | 14 | 11 | |||||||||||
ComEd | 7 | 5 | |||||||||||
PECO | 2 | 2 | |||||||||||
BGE | 3 | 2 | |||||||||||
BSC(a) | 3 | 2 | |||||||||||
These amounts primarily represent amounts billed to Exelon's subsidiaries through intercompany allocations. These costs are not included in the Generation, ComEd, PECO or BGE amounts above. | |||||||||||||
Serverance_And_Plant_Retiremen
Serverance And Plant Retirements (Tables) | 3 Months Ended | ||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||
Corporate Restructuring And Plant Retirements Tables [Abstract] | ' | ||||||||||||||||
Activity of severance obligations for the corporate restructuring (excluding obligations recorded in equity) | ' | ||||||||||||||||
Severance Liability | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||
Balance at December 31, 2013 | $ | 53 | $ | 10 | $ | 0 | $ | 0 | $ | 6 | |||||||
Payments | -12 | -1 | 0 | 0 | -2 | ||||||||||||
Balance at March 31, 2014 | $ | 41 | $ | 9 | $ | 0 | $ | 0 | $ | 4 | |||||||
Schedule Of Severance Costs [TableTextBlock] | ' | ||||||||||||||||
Severance Benefits | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||
Severance charges - 2014 | $ | 4 | $ | 4 | $ | 0 | $ | 0 | $ | 0 | |||||||
Severance charges - 2013 | 1 | 0 | 1 | 0 | 0 |
Changes_in_Accumulated_Other_C1
Changes in Accumulated Other Comprehensive Income (Tables) | 3 Months Ended | |||||||||||||||||||||||||||
Mar. 31, 2014 | Mar. 31, 2013 | |||||||||||||||||||||||||||
Accumulated Other Comprehensive Income Loss [Line Items] | ' | ' | ||||||||||||||||||||||||||
Schedule Of Accumulated Other Comprehensive Income Loss Table [Text Block] | ' | ' | ||||||||||||||||||||||||||
For the Three Months Ended March 31, 2014 | 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 | For the Three Months Ended March 31, 2013 | Gains and (Losses) on Cash Flow Hedges | Unrealized Gains and (Losses) on Marketable Securities | Pension and Non-Pension Postretirement Benefit Plan items | Foreign Currency Items | AOCI of Equity Investments | Total | |||||||||||||||
Exelon (a) | Exelon (a) | |||||||||||||||||||||||||||
Beginning balance | $ | 120 | $ | 2 | $ | -2,260 | $ | -10 | $ | 108 | $ | -2,040 | Beginning balance | $ | 368 | $ | 0 | $ | -3,137 | $ | 0 | $ | 2 | $ | -2,767 | |||
OCI before reclassifications | -1 | 0 | -13 | -5 | 11 | -8 | OCI before reclassifications | 0 | -1 | 76 | -1 | 26 | 100 | |||||||||||||||
Amounts reclassified from AOCI (b) | -24 | 0 | 35 | 0 | 1 | 12 | Amounts reclassified from AOCI (b) | -58 | 0 | 50 | 0 | 2 | -6 | |||||||||||||||
Net current-period OCI | -25 | 0 | 22 | -5 | 12 | 4 | Net current-period OCI | -58 | -1 | 126 | -1 | 28 | 94 | |||||||||||||||
Ending balance | $ | 95 | $ | 2 | $ | -2,238 | $ | -15 | $ | 120 | $ | -2,036 | Ending balance | $ | 310 | $ | -1 | $ | -3,011 | $ | -1 | $ | 30 | $ | -2,673 | |||
Generation (a) | Generation (a) | |||||||||||||||||||||||||||
Beginning balance | $ | 114 | $ | 2 | $ | 0 | $ | -10 | $ | 108 | $ | 214 | Beginning balance | $ | 513 | $ | -1 | $ | -19 | $ | 0 | $ | 20 | $ | 513 | |||
OCI before reclassifications | -1 | -3 | 0 | -5 | 11 | 2 | OCI before reclassifications | 5 | -1 | 0 | -1 | 26 | 29 | |||||||||||||||
Amounts reclassified from AOCI (b) | -24 | 0 | 0 | 0 | 1 | -23 | Amounts reclassified from AOCI (b) | -135 | 0 | 0 | 0 | 2 | -133 | |||||||||||||||
Net current-period OCI | -25 | -3 | 0 | -5 | 12 | -21 | Net current-period OCI | -130 | -1 | 0 | -1 | 28 | -104 | |||||||||||||||
Ending balance | $ | 89 | $ | -1 | $ | 0 | $ | -15 | $ | 120 | $ | 193 | Ending balance | $ | 383 | $ | -2 | $ | -19 | $ | -1 | $ | 48 | $ | 409 | |||
ComEd (a) | ComEd (a) | |||||||||||||||||||||||||||
PECO (a) | PECO (a) | |||||||||||||||||||||||||||
Beginning balance | $ | 0 | $ | 1 | $ | 0 | $ | 0 | $ | 0 | $ | 1 | Beginning balance | $ | 0 | $ | 1 | $ | 0 | $ | 0 | $ | 0 | $ | 1 | |||
OCI before reclassifications | 0 | 0 | 0 | 0 | 0 | 0 | OCI before reclassifications | 0 | 0 | 0 | 0 | 0 | 0 | |||||||||||||||
Amounts reclassified from AOCI (b) | 0 | 0 | 0 | 0 | 0 | 0 | Amounts reclassified from AOCI (b) | 0 | 0 | 0 | 0 | 0 | 0 | |||||||||||||||
Net current-period OCI | 0 | 0 | 0 | 0 | 0 | 0 | Net current-period OCI | 0 | 0 | 0 | 0 | 0 | 0 | |||||||||||||||
Ending balance | $ | 0 | $ | 1 | $ | 0 | $ | 0 | $ | 0 | $ | 1 | Ending balance | $ | 0 | $ | 1 | $ | 0 | $ | 0 | $ | 0 | $ | 1 | |||
BGE (a) | BGE (a) | |||||||||||||||||||||||||||
(a) All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income. | ||||||||||||||||||||||||||||
(b) See tables following changes in accumulated other comprehensive income tables for details about these reclassifications. | ||||||||||||||||||||||||||||
Schedule Of Other Comprehensive Income Loss Tax Table [TextBlock] | ' | ' | ||||||||||||||||||||||||||
Three Months Ended | ||||||||||||||||||||||||||||
March 31, | ||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||
Exelon | ||||||||||||||||||||||||||||
Pension and non-pension postretirement benefit plans: | ||||||||||||||||||||||||||||
Prior service benefit reclassified to periodic benefit cost | $ | -1 | $ | 0 | ||||||||||||||||||||||||
Actuarial loss reclassified to periodic cost | -23 | -32 | ||||||||||||||||||||||||||
Pension and non-pension postretirement benefit plans valuation | ||||||||||||||||||||||||||||
adjustment | 7 | -49 | ||||||||||||||||||||||||||
Change in unrealized loss on cash flow hedges | 18 | 33 | ||||||||||||||||||||||||||
Change in unrealized income on equity investments | -7 | -18 | ||||||||||||||||||||||||||
Total | $ | -6 | $ | -66 | ||||||||||||||||||||||||
Generation | ||||||||||||||||||||||||||||
Change in unrealized gain (loss) on cash flow hedges | $ | 19 | $ | 86 | ||||||||||||||||||||||||
Change in unrealized income on equity investments | -7 | -18 | ||||||||||||||||||||||||||
Change in unrealized loss on marketable securities | -2 | 0 | ||||||||||||||||||||||||||
Total | $ | 10 | $ | 68 | ||||||||||||||||||||||||
Earnings_Per_Share_and_Equity_1
Earnings Per Share and Equity (Tables) | 3 Months Ended | ||||||
Mar. 31, 2014 | |||||||
Earnings Per Share and Equity Tables [Abstract] | ' | ||||||
Reconciliation of basic and diluted earnings per share | ' | ||||||
Three Months Ended March 31, | |||||||
2014 | 2013 | ||||||
Net income (loss) attributable to common shareholders | $ | 90 | $ | -4 | |||
Weighted average common shares outstanding - basic | 858 | 855 | |||||
Assumed exercise and/or distributions of stock based awards | 3 | 0 | |||||
Weighted average common shares outstanding - diluted | 861 | 855 |
Commitments_and_Contingencies_1
Commitments and Contingencies (Tables) | 3 Months Ended | |||||||||||||||||||||||||
Mar. 31, 2014 | ||||||||||||||||||||||||||
Commitments And Contingencies Tables Disclosure [Line Items] | ' | |||||||||||||||||||||||||
Energy Commitments [Text Block] | ' | |||||||||||||||||||||||||
Net Capacity | REC | Transmission Rights | Purchased Energy | |||||||||||||||||||||||
Purchases (a) | Purchases (b) | Purchases (c) | from CENG | Total | ||||||||||||||||||||||
2014 | $ | 314 | $ | 100 | $ | 19 | $ | 640 | $ | 1,073 | ||||||||||||||||
2015 | 367 | 141 | 13 | 0 | 521 | |||||||||||||||||||||
2016 | 284 | 96 | 2 | 0 | 382 | |||||||||||||||||||||
2017 | 223 | 42 | 2 | 0 | 267 | |||||||||||||||||||||
2018 | 112 | 8 | 2 | 0 | 122 | |||||||||||||||||||||
Thereafter | 414 | 4 | 32 | 0 | 450 | |||||||||||||||||||||
Total | $ | 1,714 | $ | 391 | $ | 70 | $ | 640 | $ | 2,815 | ||||||||||||||||
(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 March 31, 2014, net of fixed capacity payments expected to be received by Generation under contracts to resell such acquired capacity to third parties under long-term capacity sale contracts. Expected payments include certain fixed capacity charges which may be reduced based on plant availability. | ||||||||||||||||||||||||||
(b) The table excludes renewable energy purchases that are contingent in nature. | ||||||||||||||||||||||||||
(c) Transmission rights purchases include estimated commitments for additional transmission rights that will be required to fulfill firm sales contracts. | ||||||||||||||||||||||||||
Utility Energy Purchase Commitments [Text Block] | ' | |||||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||||
2019 | ||||||||||||||||||||||||||
Total | 2014 | 2015 | 2016 | 2017 | 2018 | and beyond | ||||||||||||||||||||
ComEd | ||||||||||||||||||||||||||
Electric supply procurement (a) | $ | 591 | $ | 178 | $ | 136 | $ | 137 | $ | 140 | $ | 0 | $ | 0 | ||||||||||||
Renewable energy and RECs (b) | 1,565 | 50 | 72 | 76 | 77 | 83 | 1,207 | |||||||||||||||||||
PECO | ||||||||||||||||||||||||||
Electric supply procurement (c) | 713 | 546 | 167 | 0 | 0 | 0 | 0 | |||||||||||||||||||
AECs (d) | 14 | 2 | 2 | 2 | 2 | 2 | 4 | |||||||||||||||||||
BGE | ||||||||||||||||||||||||||
Electric supply procurement (e) | 1,026 | 541 | 409 | 76 | 0 | 0 | 0 | |||||||||||||||||||
Curtailment services (f) | 120 | 33 | 40 | 34 | 13 | 0 | 0 | |||||||||||||||||||
(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. | ||||||||||||||||||||||||||
(b) ComEd entered into 20-year contracts for renewable energy and RECs beginning in June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. The commitments represent the maximum settlements with suppliers for renewable energy and RECs under the existing contract terms. Pursuant to the ICC's Order on December 19, 2012, ComEd's commitments under the existing long-term contracts were reduced for the June 2013 through May 2014 procurement period. In addition, the ICC's December 18, 2013 order approved the reduction of ComEd's commitments under those contracts for the June 2014 through May 2015 procurement period, and the amount of the reduction was approved by the ICC in March 2014. | ||||||||||||||||||||||||||
(c) PECO entered into various contracts for the procurement of electric supply to serve its default service customers that expire between 2014 and 2016. PECO is permitted to recover its electric supply procurement costs from default service customers with no mark-up in accordance with its PAPUC-approved DSP Programs. See Note 4 - Regulatory Matters for additional information. | ||||||||||||||||||||||||||
(d) PECO is subject to requirements related to the use of alternative energy resources established by the AEPS Act. See Note 4 - Regulatory Matters for additional information. | ||||||||||||||||||||||||||
(e) BGE entered into various contracts for the procurement of electricity that expire between 2014 through 2016. The cost of power under these contracts is recoverable under MDPSC approved fuel clauses. See Note 4 - Regulatory Matters for additional information. | ||||||||||||||||||||||||||
(f) BGE has entered into various contracts with curtailment services providers related to transactions in PJM's capacity market. See Note 4 - Regulatory Matters for additional information. | ||||||||||||||||||||||||||
Fuel Purchase Commitments [Text Block] | ' | |||||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||||
2019 | ||||||||||||||||||||||||||
Total | 2014 | 2015 | 2016 | 2017 | 2018 | and beyond | ||||||||||||||||||||
Generation | $ | 8,402 | $ | 1,036 | $ | 1,285 | $ | 1,039 | $ | 1,041 | $ | 780 | $ | 3,221 | ||||||||||||
PECO | 479 | 146 | 117 | 98 | 37 | 15 | 66 | |||||||||||||||||||
BGE | 640 | 105 | 82 | 80 | 63 | 52 | 258 | |||||||||||||||||||
Commercial Commitments [Text Block] | ' | |||||||||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||||||||
Letters of credit (non-debt) (a) | $ | 1,717 | $ | 1,675 | $ | 17 | $ | 22 | $ | 1 | ||||||||||||||||
Guarantees | 4,644 | (b) | 1,287 | (c) | 205 | (d) | 181 | (e) | 259 | (f) | ||||||||||||||||
Nuclear insurance premiums (g) | 3,529 | 3,529 | 0 | 0 | 0 | |||||||||||||||||||||
Total commercial commitments | $ | 9,890 | $ | 6,491 | $ | 222 | $ | 203 | $ | 260 | ||||||||||||||||
(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 $0.5 billion at March 31, 2014, which represents the total amount Exelon could be required to fund based on March 31, 2014 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 $0.3 billion at March 31, 2014, which represents the total amount Generation could be required to fund based on March 31, 2014 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] | ' | |||||||||||||||||||||||||
31-Mar-14 | Total Environmental Investigation and Remediation Reserve | Portion of Total Related to MGP Investigation and Remediation | ||||||||||||||||||||||||
Exelon | $ | 332 | $ | 267 | ||||||||||||||||||||||
Generation | 56 | 0 | ||||||||||||||||||||||||
ComEd | 230 | 225 | ||||||||||||||||||||||||
PECO | 45 | 42 | ||||||||||||||||||||||||
BGE | 1 | 0 | ||||||||||||||||||||||||
31-Dec-13 | Total Environmental Investigation and Remediation Reserve | Portion of Total Related to MGP Investigation and Remediation | ||||||||||||||||||||||||
Exelon | $ | 338 | $ | 273 | ||||||||||||||||||||||
Generation | 56 | 0 | ||||||||||||||||||||||||
ComEd | 234 | 229 | ||||||||||||||||||||||||
PECO | 47 | 44 | ||||||||||||||||||||||||
BGE | 1 | 0 | ||||||||||||||||||||||||
Other Purchase Obligation [Table Text Block] | ' | |||||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||||
2019 | ||||||||||||||||||||||||||
Total | 2014 | 2015 | 2016 | 2017 | 2018 | and beyond | ||||||||||||||||||||
Exelon | $ | 547 | $ | 150 | $ | 146 | $ | 58 | $ | 49 | $ | 36 | $ | 108 | ||||||||||||
Generation | 462 | 120 | 138 | 45 | 41 | 30 | 88 | |||||||||||||||||||
ComEd (a) | 45 | 11 | 5 | 5 | 5 | 5 | 14 | |||||||||||||||||||
PECO (a) | 28 | 16 | 1 | 3 | 1 | 1 | 6 | |||||||||||||||||||
BGE (a) | 10 | 1 | 2 | 5 | 2 | 0 | 0 | |||||||||||||||||||
(a) Purchase obligations include commitments related to smart meter installation. See Note 4 – Regulatory Matters for additional information. | ||||||||||||||||||||||||||
Supplemental_Financial_Informa1
Supplemental Financial Information (Tables) | 3 Months Ended | |||||||||||||||||||||||||||||||
Mar. 31, 2014 | Mar. 31, 2013 | |||||||||||||||||||||||||||||||
Supplemental Financial Information Tables [Line Items] | ' | ' | ||||||||||||||||||||||||||||||
Components of non-operating income and expenses | ' | ' | ||||||||||||||||||||||||||||||
__________ | ||||||||||||||||||||||||||||||||
Three Months Ended March 31, 2014 | Exelon | Generation | ComEd | PECO | BGE | (a) Includes investment income and realized gains and losses on sales of investments of the trust funds. | ||||||||||||||||||||||||||
Other, Net | (b) Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of net income taxes related to all NDT fund activity for those units. See Note 15 – Asset Retirement Obligations of the Exelon 2013 Form 10-K for additional information regarding the accounting for nuclear decommissioning. | |||||||||||||||||||||||||||||||
Decommissioning-related activities: | (c) Relates to the cash return on BGE's rate stabilization deferral. See Note 4 - Regulatory Matters for additional information regarding the rate stabilization deferral. | |||||||||||||||||||||||||||||||
Net realized income on decommissioning trust funds (a) | ||||||||||||||||||||||||||||||||
Regulatory agreement units | $ | 43 | $ | 43 | $ | 0 | $ | 0 | $ | 0 | ||||||||||||||||||||||
Non-regulatory agreement units | 25 | 25 | 0 | 0 | 0 | |||||||||||||||||||||||||||
Net unrealized gains on decommissioning trust funds | ||||||||||||||||||||||||||||||||
Regulatory agreement units | 61 | 61 | 0 | 0 | 0 | |||||||||||||||||||||||||||
Non-regulatory agreement units | 13 | 13 | 0 | 0 | 0 | |||||||||||||||||||||||||||
Net unrealized gains on pledged assets | ||||||||||||||||||||||||||||||||
Zion Station decommissioning | 10 | 10 | 0 | 0 | 0 | |||||||||||||||||||||||||||
Regulatory offset to decommissioning trust fund-related | ||||||||||||||||||||||||||||||||
activities (b) | -94 | -94 | 0 | 0 | 0 | |||||||||||||||||||||||||||
Total decommissioning-related activities | 58 | 58 | 0 | 0 | 0 | |||||||||||||||||||||||||||
Investment income (expense) | 1 | 1 | 0 | 0 | 2 | (c) | ||||||||||||||||||||||||||
Long-term lease income | 6 | 0 | 0 | 0 | 0 | |||||||||||||||||||||||||||
Interest income related to uncertain income tax positions | 10 | 14 | 0 | 0 | 0 | |||||||||||||||||||||||||||
AFUDC - Equity | 6 | 0 | 3 | 1 | 3 | |||||||||||||||||||||||||||
Other | 22 | 17 | 2 | 1 | -1 | |||||||||||||||||||||||||||
Other, net | $ | 103 | $ | 90 | $ | 5 | $ | 2 | $ | 4 | ||||||||||||||||||||||
Three Months Ended March 31, 2013 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||||||||||||||
Other, Net | ||||||||||||||||||||||||||||||||
Decommissioning-related activities: | ||||||||||||||||||||||||||||||||
Net realized income on decommissioning trust funds (a) | ||||||||||||||||||||||||||||||||
Regulatory agreement units | $ | 36 | $ | 36 | $ | 0 | $ | 0 | $ | 0 | ||||||||||||||||||||||
Non-regulatory agreement units | 14 | 14 | 0 | 0 | 0 | |||||||||||||||||||||||||||
Net unrealized gains on decommissioning trust funds | ||||||||||||||||||||||||||||||||
Regulatory agreement units | 195 | 195 | 0 | 0 | 0 | |||||||||||||||||||||||||||
Non-regulatory agreement units | 64 | 64 | 0 | 0 | 0 | |||||||||||||||||||||||||||
Net unrealized gains on pledged assets | ||||||||||||||||||||||||||||||||
Zion Station decommissioning | 2 | 2 | 0 | 0 | 0 | |||||||||||||||||||||||||||
Regulatory offset to decommissioning trust fund-related | ||||||||||||||||||||||||||||||||
activities (b) | -190 | -190 | 0 | 0 | 0 | |||||||||||||||||||||||||||
Total decommissioning-related activities | 121 | 121 | 0 | 0 | 0 | |||||||||||||||||||||||||||
Investment income (expense) | 3 | -2 | 0 | 0 | 2 | (c) | ||||||||||||||||||||||||||
Long-term lease income | 8 | 0 | 0 | 0 | 0 | |||||||||||||||||||||||||||
Interest income related to uncertain income tax provisions | 25 | 5 | 0 | 0 | 0 | |||||||||||||||||||||||||||
AFUDC - Equity | 6 | 0 | 3 | 1 | 2 | |||||||||||||||||||||||||||
Other | 9 | 4 | 2 | 2 | 1 | |||||||||||||||||||||||||||
Other, net | $ | 172 | $ | 128 | $ | 5 | $ | 3 | $ | 5 | ||||||||||||||||||||||
__________ | ||||||||||||||||||||||||||||||||
(a) Includes investment income and realized gains and losses on sales of investments of the trust funds. | ||||||||||||||||||||||||||||||||
(b) Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of net income taxes related to all NDT fund activity for those units. See Note 15 – Asset Retirement Obligations of the Exelon 2013 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 4 - Regulatory Matters for additional information regarding the rate stabilization deferral. | ||||||||||||||||||||||||||||||||
Components of depreciation, amortization and accretion, and other, net | ' | ' | ||||||||||||||||||||||||||||||
Three Months Ended March 31, 2014 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||||||||||||||
Depreciation, amortization, accretion and depletion | ||||||||||||||||||||||||||||||||
Property, plant and equipment | $ | 481 | $ | 200 | $ | 143 | $ | 56 | $ | 70 | ||||||||||||||||||||||
Regulatory assets | 72 | 0 | 30 | 2 | 38 | |||||||||||||||||||||||||||
Amortization of intangible assets, net | 11 | 11 | 0 | 0 | 0 | |||||||||||||||||||||||||||
Amortization of energy contract assets and liabilities (a) | 42 | 44 | 0 | 0 | 0 | |||||||||||||||||||||||||||
Nuclear fuel (b) | 234 | 234 | 0 | 0 | 0 | |||||||||||||||||||||||||||
ARO accretion (c) | 68 | 68 | 0 | 0 | 0 | |||||||||||||||||||||||||||
Total depreciation, amortization, accretion and depletion | $ | 908 | $ | 557 | $ | 173 | $ | 58 | $ | 108 | ||||||||||||||||||||||
Three Months Ended March 31, 2013 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||||||||||||||
Depreciation, amortization, accretion and depletion | ||||||||||||||||||||||||||||||||
Property, plant and equipment | $ | 471 | $ | 203 | $ | 137 | $ | 55 | $ | 64 | ||||||||||||||||||||||
Regulatory assets | 61 | 0 | 30 | 2 | 29 | |||||||||||||||||||||||||||
Amortization of intangible assets, net | 11 | 11 | 0 | 0 | 0 | |||||||||||||||||||||||||||
Amortization of energy contract assets and liabilities (a) | 176 | 176 | 0 | 0 | 0 | |||||||||||||||||||||||||||
Nuclear fuel (b) | 230 | 230 | 0 | 0 | 0 | |||||||||||||||||||||||||||
ARO accretion (c) | 68 | 68 | 0 | 0 | 0 | |||||||||||||||||||||||||||
Total depreciation, amortization, accretion and depletion | $ | 1,017 | $ | 688 | $ | 167 | $ | 57 | $ | 93 | ||||||||||||||||||||||
__________ | ||||||||||||||||||||||||||||||||
(a) Included in Operating revenues or Purchased power and fuel expense on the Registrants' Consolidated Statements of Operations and Comprehensive Income. | ||||||||||||||||||||||||||||||||
(b) Included in Purchased power and fuel expense on the Registrants' Consolidated Statements of Operations and Comprehensive Income. | ||||||||||||||||||||||||||||||||
(c) Included in Operating and maintenance expense on the Registrants' Consolidated Statements of Operations and Comprehensive Income. | ||||||||||||||||||||||||||||||||
Cash Flow Supplemental Disclosures | ' | ' | ||||||||||||||||||||||||||||||
Three Months Ended March 31, 2014 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||||||||||||||
Other non-cash operating activities: | ||||||||||||||||||||||||||||||||
Pension and non-pension postretirement benefit costs | $ | 173 | $ | 75 | $ | 56 | $ | 12 | $ | 16 | ||||||||||||||||||||||
Loss from equity method investments | 19 | 19 | 0 | 0 | 0 | |||||||||||||||||||||||||||
Provision for uncollectible accounts | 35 | 1 | -11 | 35 | 11 | |||||||||||||||||||||||||||
Stock-based compensation costs | 46 | 0 | 0 | 0 | 0 | |||||||||||||||||||||||||||
Other decommissioning-related activity (a) | -35 | -35 | 0 | 0 | 0 | |||||||||||||||||||||||||||
Energy-related options (b) | 31 | 31 | 0 | 0 | 0 | |||||||||||||||||||||||||||
Amortization of regulatory asset related to debt costs | 3 | 0 | 2 | 1 | 0 | |||||||||||||||||||||||||||
Amortization of rate stabilization deferral | 20 | 0 | 0 | 0 | 20 | |||||||||||||||||||||||||||
Amortization of debt fair value adjustment | -12 | -5 | 0 | 0 | 0 | |||||||||||||||||||||||||||
Discrete impacts of EIMA (c) | -4 | 0 | -4 | 0 | 0 | |||||||||||||||||||||||||||
Amortization of debt costs | 5 | 3 | -5 | 1 | 0 | |||||||||||||||||||||||||||
Increase in inventory reserve | 2 | 2 | 0 | 0 | 0 | |||||||||||||||||||||||||||
Other | -11 | -6 | -2 | 0 | -4 | |||||||||||||||||||||||||||
Total other non-cash operating activities | $ | 272 | $ | 85 | $ | 36 | $ | 49 | $ | 43 | ||||||||||||||||||||||
Changes in other assets and liabilities: | ||||||||||||||||||||||||||||||||
Under/over-recovered energy and transmission costs | $ | -15 | $ | 0 | $ | 4 | $ | -17 | $ | 23 | ||||||||||||||||||||||
Other regulatory assets and liabilities | -4 | 0 | -10 | -3 | 6 | |||||||||||||||||||||||||||
Other current assets | -209 | -80 | -29 | -105 | (e) | 18 | ||||||||||||||||||||||||||
Other noncurrent assets and liabilities | -50 | -23 | 11 | -2 | -3 | |||||||||||||||||||||||||||
Total changes in other assets and liabilities | $ | -278 | $ | -103 | $ | -24 | $ | -127 | $ | 44 | ||||||||||||||||||||||
Non-cash investing and financing activities: | ||||||||||||||||||||||||||||||||
Indemnification of like-kind exchange position (f) | $ | 0 | $ | 0 | $ | 2 | $ | 0 | $ | 0 | ||||||||||||||||||||||
Total non-cash investing and financing activities: | $ | 0 | $ | 0 | $ | 2 | $ | 0 | $ | 0 | ||||||||||||||||||||||
Three Months Ended March 31, 2013 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||||||||||||||
Other non-cash operating activities: | ||||||||||||||||||||||||||||||||
Pension and non-pension postretirement benefit costs | $ | 205 | $ | 87 | $ | 77 | $ | 11 | $ | 14 | ||||||||||||||||||||||
Loss in equity method investments | 9 | 9 | 0 | 0 | 0 | |||||||||||||||||||||||||||
Provision for uncollectible accounts | 45 | 7 | 9 | 25 | 4 | |||||||||||||||||||||||||||
Stock-based compensation costs | 39 | 4 | 1 | 1 | 1 | |||||||||||||||||||||||||||
Other decommissioning-related activity (a) | -64 | -64 | 0 | 0 | 0 | |||||||||||||||||||||||||||
Energy-related options (b) | 21 | 21 | 0 | 0 | 0 | |||||||||||||||||||||||||||
Amortization of regulatory asset related to debt costs | 4 | 0 | 3 | 1 | 0 | |||||||||||||||||||||||||||
Amortization of rate stabilization deferral | 30 | 0 | 0 | 0 | 30 | |||||||||||||||||||||||||||
Amortization of debt fair value adjustment | -9 | -9 | 0 | 0 | 0 | |||||||||||||||||||||||||||
Discrete impacts from EIMA (c) | -49 | 0 | -49 | 0 | 0 | |||||||||||||||||||||||||||
Amortization of debt costs | 5 | 3 | 1 | 1 | 0 | |||||||||||||||||||||||||||
Merger integration costs (d) | -6 | 0 | 0 | 0 | -6 | |||||||||||||||||||||||||||
Other | 1 | 8 | 0 | 0 | -1 | |||||||||||||||||||||||||||
Total other non-cash operating activities | $ | 231 | $ | 66 | $ | 42 | $ | 39 | $ | 42 | ||||||||||||||||||||||
Changes in other assets and liabilities: | ||||||||||||||||||||||||||||||||
Under/over-recovered energy and transmission costs | $ | 29 | $ | 0 | $ | -18 | $ | 22 | $ | 16 | ||||||||||||||||||||||
Other regulatory assets and liabilities | 91 | 0 | -14 | 13 | -53 | |||||||||||||||||||||||||||
Other current assets | -169 | -131 | 17 | -75 | (e) | 73 | ||||||||||||||||||||||||||
Other noncurrent assets and liabilities | 282 | -28 | 263 | 2 | -2 | |||||||||||||||||||||||||||
Total changes in other assets and liabilities | $ | 233 | $ | -159 | $ | 248 | $ | -38 | $ | 34 | ||||||||||||||||||||||
Non-cash investing and financing activities: | ||||||||||||||||||||||||||||||||
Consolidated VIE dividend to non-controlling interest | $ | 63 | 63 | 0 | 0 | 0 | ||||||||||||||||||||||||||
Indemnification of like-kind exchange position (f) | 0 | 0 | 172 | 0 | 0 | |||||||||||||||||||||||||||
Total non-cash investing and financing activities | $ | 63 | $ | 63 | $ | 172 | $ | 0 | $ | 0 | ||||||||||||||||||||||
_________ | ||||||||||||||||||||||||||||||||
(a) Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 15 of the Exelon 2013 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 4 - Regulatory Matters for more information. | ||||||||||||||||||||||||||||||||
(d) Relates to integration costs to achieve distribution synergies related to the merger transaction. See Note 4 - Regulatory Matters for more information. | ||||||||||||||||||||||||||||||||
(e) Relates primarily to prepaid utility taxes. | ||||||||||||||||||||||||||||||||
(f) See Note 9 – Income Taxes for discussion of the like-kind exchange tax position. | ||||||||||||||||||||||||||||||||
Supplemental Balance Sheet Disclosures | ' | ' | ||||||||||||||||||||||||||||||
31-Mar-14 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||||||||||||||
Property, plant and equipment: | ||||||||||||||||||||||||||||||||
Accumulated depreciation and amortization | $ | 14,066 | (a) | $ | 7,245 | (a) | $ | 3,247 | $ | 2,958 | $ | 2,741 | ||||||||||||||||||||
Accounts receivable: | ||||||||||||||||||||||||||||||||
Allowance for uncollectible accounts | 306 | 46 | 76 | 140 | 44 | |||||||||||||||||||||||||||
31-Dec-13 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||||||||||||||
Property, plant and equipment: | ||||||||||||||||||||||||||||||||
Accumulated depreciation and amortization | $ | 13,713 | (b) | $ | 7,034 | (b) | $ | 3,184 | $ | 2,935 | $ | 2,702 | ||||||||||||||||||||
Accounts receivable: | ||||||||||||||||||||||||||||||||
Allowance for uncollectible accounts | 272 | 57 | 62 | 107 | 46 | |||||||||||||||||||||||||||
___________ | ||||||||||||||||||||||||||||||||
(a) Includes accumulated amortization of nuclear fuel in the reactor core of $2,425 million. | ||||||||||||||||||||||||||||||||
(b) Includes accumulated amortization of nuclear fuel in the reactor core of $2,371 million. | ||||||||||||||||||||||||||||||||
Capital Leases Net Investment In Direct Financing Leases Table | ' | ' | ||||||||||||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | |||||||||||||||||||||||||||||||
Estimated residual value of leased assets | $ | 731 | $ | 1,465 | ||||||||||||||||||||||||||||
Less: unearned income | 363 | 767 | ||||||||||||||||||||||||||||||
Net investment in long-term leases | $ | 368 | $ | 698 | ||||||||||||||||||||||||||||
Accumulated Other Comprehensive Income Net Of Taxes | ' | ' | ||||||||||||||||||||||||||||||
For the Three Months Ended March 31, 2014 | 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 | For the Three Months Ended March 31, 2013 | Gains and (Losses) on Cash Flow Hedges | Unrealized Gains and (Losses) on Marketable Securities | Pension and Non-Pension Postretirement Benefit Plan items | Foreign Currency Items | AOCI of Equity Investments | Total | |||||||||||||||||||
Exelon (a) | Exelon (a) | |||||||||||||||||||||||||||||||
Beginning balance | $ | 120 | $ | 2 | $ | -2,260 | $ | -10 | $ | 108 | $ | -2,040 | Beginning balance | $ | 368 | $ | 0 | $ | -3,137 | $ | 0 | $ | 2 | $ | -2,767 | |||||||
OCI before reclassifications | -1 | 0 | -13 | -5 | 11 | -8 | OCI before reclassifications | 0 | -1 | 76 | -1 | 26 | 100 | |||||||||||||||||||
Amounts reclassified from AOCI (b) | -24 | 0 | 35 | 0 | 1 | 12 | Amounts reclassified from AOCI (b) | -58 | 0 | 50 | 0 | 2 | -6 | |||||||||||||||||||
Net current-period OCI | -25 | 0 | 22 | -5 | 12 | 4 | Net current-period OCI | -58 | -1 | 126 | -1 | 28 | 94 | |||||||||||||||||||
Ending balance | $ | 95 | $ | 2 | $ | -2,238 | $ | -15 | $ | 120 | $ | -2,036 | Ending balance | $ | 310 | $ | -1 | $ | -3,011 | $ | -1 | $ | 30 | $ | -2,673 | |||||||
Generation (a) | Generation (a) | |||||||||||||||||||||||||||||||
Beginning balance | $ | 114 | $ | 2 | $ | 0 | $ | -10 | $ | 108 | $ | 214 | Beginning balance | $ | 513 | $ | -1 | $ | -19 | $ | 0 | $ | 20 | $ | 513 | |||||||
OCI before reclassifications | -1 | -3 | 0 | -5 | 11 | 2 | OCI before reclassifications | 5 | -1 | 0 | -1 | 26 | 29 | |||||||||||||||||||
Amounts reclassified from AOCI (b) | -24 | 0 | 0 | 0 | 1 | -23 | Amounts reclassified from AOCI (b) | -135 | 0 | 0 | 0 | 2 | -133 | |||||||||||||||||||
Net current-period OCI | -25 | -3 | 0 | -5 | 12 | -21 | Net current-period OCI | -130 | -1 | 0 | -1 | 28 | -104 | |||||||||||||||||||
Ending balance | $ | 89 | $ | -1 | $ | 0 | $ | -15 | $ | 120 | $ | 193 | Ending balance | $ | 383 | $ | -2 | $ | -19 | $ | -1 | $ | 48 | $ | 409 | |||||||
ComEd (a) | ComEd (a) | |||||||||||||||||||||||||||||||
PECO (a) | PECO (a) | |||||||||||||||||||||||||||||||
Beginning balance | $ | 0 | $ | 1 | $ | 0 | $ | 0 | $ | 0 | $ | 1 | Beginning balance | $ | 0 | $ | 1 | $ | 0 | $ | 0 | $ | 0 | $ | 1 | |||||||
OCI before reclassifications | 0 | 0 | 0 | 0 | 0 | 0 | OCI before reclassifications | 0 | 0 | 0 | 0 | 0 | 0 | |||||||||||||||||||
Amounts reclassified from AOCI (b) | 0 | 0 | 0 | 0 | 0 | 0 | Amounts reclassified from AOCI (b) | 0 | 0 | 0 | 0 | 0 | 0 | |||||||||||||||||||
Net current-period OCI | 0 | 0 | 0 | 0 | 0 | 0 | Net current-period OCI | 0 | 0 | 0 | 0 | 0 | 0 | |||||||||||||||||||
Ending balance | $ | 0 | $ | 1 | $ | 0 | $ | 0 | $ | 0 | $ | 1 | Ending balance | $ | 0 | $ | 1 | $ | 0 | $ | 0 | $ | 0 | $ | 1 | |||||||
BGE (a) | BGE (a) | |||||||||||||||||||||||||||||||
(a) All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income. | ||||||||||||||||||||||||||||||||
(b) See tables following changes in accumulated other comprehensive income tables for details about these reclassifications. |
Segment_Information_Tables
Segment Information (Tables) | 3 Months Ended | ||||||||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||||||||
Segment Reporting Information [Line Items] | ' | ||||||||||||||||||||||
Analysis and reconciliation of reportable segment information | ' | ||||||||||||||||||||||
Intersegment Eliminations | |||||||||||||||||||||||
Generation (a) | ComEd | PECO | BGE | Other (b) | Exelon | ||||||||||||||||||
Total revenues (c): | |||||||||||||||||||||||
2014 | $ | 4,390 | $ | 1,134 | $ | 993 | $ | 1,054 | $ | 290 | $ | -624 | $ | 7,237 | |||||||||
2013 | 3,533 | 1,160 | 895 | 880 | 318 | -704 | 6,082 | ||||||||||||||||
Intersegment revenues (d): | |||||||||||||||||||||||
2014 | $ | 316 | $ | 1 | $ | 1 | $ | 16 | $ | 290 | $ | -623 | $ | 1 | |||||||||
2013 | 381 | 1 | 0 | 4 | 318 | -704 | 0 | ||||||||||||||||
Net income (loss): | |||||||||||||||||||||||
2014 | $ | -185 | $ | 98 | $ | 89 | $ | 88 | $ | 4 | $ | -1 | $ | 93 | |||||||||
2013 | -17 | -81 | 122 | 80 | -103 | 0 | 1 | ||||||||||||||||
Total assets: | |||||||||||||||||||||||
31-Mar-14 | $ | 41,080 | $ | 24,294 | $ | 9,766 | $ | 7,958 | $ | 8,146 | $ | -11,776 | $ | 79,468 | |||||||||
31-Dec-13 | 41,232 | 24,118 | 9,617 | 7,861 | 8,317 | -11,221 | 79,924 | ||||||||||||||||
__________ | |||||||||||||||||||||||
(a) Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions. Intersegment revenues for Generation for the three months ended March 31, 2014 include revenue from sales to PECO of $88 million and sales to BGE of $120 million in the Mid-Atlantic region, and sales to ComEd of $108 million in the Midwest. For the three months ended March 31, 2013 intersegment revenues for Generation include revenue from sales to PECO of $141 million and sales to BGE of $113 million in the Mid-Atlantic region, and sales to ComEd of $145 million in the Midwest region, net of ($17) 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 March 31, 2014 and 2013, utility taxes of $24 million and $21 million, respectively, are included in revenues and expenses for Generation. For the three months ended March 31, 2014 and 2013, utility taxes of $63 million and $60 million, respectively, are included in revenues and expenses for ComEd. For the three months ended March 31, 2014 and 2013, utility taxes of $35 million and $34 million, respectively, are included in revenues and expenses for PECO. For the three months ended March 31, 2014 and 2013, utility taxes of $20 million and $22 million, respectively, are included in revenues and expenses for BGE. | |||||||||||||||||||||||
(d) Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation's sale of certain products and services by and between Exelon's segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in operating revenues in the Consolidated Statements of Operations and Comprehensive Income. | |||||||||||||||||||||||
Exelon Generation Co L L C [Member] | ' | ||||||||||||||||||||||
Segment Reporting Information [Line Items] | ' | ||||||||||||||||||||||
Analysis and reconciliation of reportable segment revenues net of purchased power and fuel expense for Generation | ' | ||||||||||||||||||||||
Generation total revenues net of purchased power and fuel expense (three months ended): | |||||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||||
RNF from external customers (a) | Intersegment RNF | Total RNF | RNF from external customers (a) | Intersegment RNF | Total RNF | ||||||||||||||||||
Mid-Atlantic | $ | 784 | $ | -89 | $ | 695 | $ | 852 | $ | -8 | $ | 844 | |||||||||||
Midwest | 530 | 26 | 556 | 710 | 7 | 717 | |||||||||||||||||
New England | 154 | -18 | 136 | 18 | 12 | 30 | |||||||||||||||||
New York | -29 | 8 | -21 | -16 | -6 | -22 | |||||||||||||||||
ERCOT | 155 | -72 | 83 | 112 | -11 | 101 | |||||||||||||||||
Other Regions (b) | 150 | -45 | 105 | 10 | 35 | 45 | |||||||||||||||||
Total Revenues net of purchased power and fuel expense for Reportable Segments | 1,744 | -190 | 1,554 | 1,686 | 29 | 1,715 | |||||||||||||||||
Other (c) | -711 | 190 | -521 | -322 | -29 | -351 | |||||||||||||||||
Total Generation Revenues net of purchased power and fuel expense | $ | 1,033 | $ | 0 | $ | 1,033 | $ | 1,364 | $ | - | $ | 1,364 | |||||||||||
(a) Includes purchases and sales from third parties and affiliated sales to ComEd, PECO and BGE. | |||||||||||||||||||||||
(b) Other regions include the South, West and Canada, which are not considered individually significant. | |||||||||||||||||||||||
(c) Other represents activities not allocated to a region. See text above for a description of included activities. Also includes amortization of intangible assets related to commodity contracts recorded at fair value of $42 million and $174 million for the three months ended March 31, 2014 and 2013, respectively, and the elimination of intersegment revenues. | |||||||||||||||||||||||
Related_Party_Transactions_Tab
Related Party Transactions (Tables) | 3 Months Ended | ||||||
Mar. 31, 2014 | |||||||
Related Party Transaction [Line Items] | ' | ||||||
Schedule Of Income Loss From Equity Method Investments [Text Block] | ' | ||||||
Three Months | Three Months | ||||||
Ended March 31, | Ended March 31, | ||||||
2014 | 2013 | ||||||
Equity investment income | $ | -2 | $ | 15 | |||
Amortization of basis difference in CENG | -17 | -27 | |||||
Total equity in earnings - CENG | $ | -19 | $ | -12 | |||
Exelon Generation Co L L C [Member] | ' | ||||||
Related Party Transaction [Line Items] | ' | ||||||
Schedule Of Income Loss From Equity Method Investments [Text Block] | ' | ||||||
Three Months | Three Months | ||||||
Ended March 31, | Ended March 31, | ||||||
2014 | 2013 | ||||||
Equity investment income | $ | -2 | $ | 15 | |||
Amortization of basis difference in CENG | -17 | -27 | |||||
Total equity in earnings - CENG | $ | -19 | $ | -12 |
Significant_Accounting_Policie
Significant Accounting Policies (Details) (USD $) | 3 Months Ended | ||
Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | |
Operating and maintenance | $1,858,000,000 | $1,764,000,000 | ' |
Interest Expense | 217,000,000 | 617,000,000 | ' |
Consolidation Percentages Detail Tagging [Abstract] | ' | ' | ' |
Third Party interest in ComEd | 17,000,000 | ' | 15,000,000 |
Exelon Generation Co L L C [Member] | ' | ' | ' |
Operating and maintenance | 938,000,000 | 965,000,000 | ' |
Interest Expense | 73,000,000 | 65,000,000 | ' |
Consolidation Percentages Detail Tagging [Abstract] | ' | ' | ' |
Equity Method Investment Ownership Percentage | 50.01% | ' | ' |
Third Party interest in ComEd | 19,000,000 | ' | 17,000,000 |
Nuclear Fuel [Abstract] | ' | ' | ' |
Cost of spent nuclear fuel disposal per kWh of net nuclear generation | 0.001 | ' | ' |
Commonwealth Edison Co [Member] | ' | ' | ' |
Electrical transmission and distribution revenue | 1,133,000,000 | 1,159,000,000 | ' |
Operating and maintenance | 287,000,000 | 292,000,000 | ' |
Interest Expense | 77,000,000 | 350,000,000 | ' |
PECO Energy Co [Member] | ' | ' | ' |
Operating and maintenance | 256,000,000 | 164,000,000 | ' |
Interest Expense | 25,000,000 | 26,000,000 | ' |
Baltimore Gas and Electric Company [Member] | ' | ' | ' |
Operating and maintenance | 163,000,000 | 124,000,000 | ' |
Interest Expense | $23,000,000 | $29,000,000 | ' |
Basis_of_Presentation_Details
Basis of Presentation (Details) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Depreciation and amortization | $564 | $543 |
Operating and maintenance | 1,858 | 1,764 |
Capital expenditures | 1,217 | 1,447 |
Income Tax Expense (Benefit) | -54 | 56 |
Interest Expense | 217 | 617 |
Total interest expense to affiliates, net | 10 | 6 |
Scenario Adjustment [Member] | ' | ' |
Purchased power and fuel from affiliate | 318 | ' |
Exelon Generation Co L L C [Member] | ' | ' |
Depreciation and amortization | 211 | 214 |
Operating and maintenance | 938 | 965 |
Capital expenditures | 535 | 841 |
Income Tax Expense (Benefit) | -199 | -1 |
Interest Expense | 73 | 65 |
Purchased power and fuel from affiliate | 349 | 321 |
Total interest expense to affiliates, net | 12 | 17 |
Exelon Generation Co L L C [Member] | Scenario Adjustment [Member] | ' | ' |
Purchased power and fuel from affiliate | 321 | ' |
Total interest expense to affiliates, net | 17 | ' |
Commonwealth Edison Co [Member] | ' | ' |
Depreciation and amortization | 173 | 167 |
Operating and maintenance | 287 | 292 |
Capital expenditures | 341 | 346 |
Income Tax Expense (Benefit) | 65 | -58 |
Interest Expense | 77 | 350 |
Total interest expense to affiliates, net | 3 | 3 |
PECO Energy Co [Member] | ' | ' |
Depreciation and amortization | 58 | 57 |
Operating and maintenance | 256 | 164 |
Capital expenditures | 184 | 122 |
Income Tax Expense (Benefit) | 34 | 55 |
Interest Expense | 25 | 26 |
Total interest expense to affiliates, net | 3 | 3 |
Baltimore Gas and Electric Company [Member] | ' | ' |
Depreciation and amortization | 108 | 93 |
Operating and maintenance | 163 | 124 |
Capital expenditures | 146 | 134 |
Income Tax Expense (Benefit) | 58 | 55 |
Interest Expense | 23 | 29 |
Total interest expense to affiliates, net | 4 | 4 |
Baltimore Gas and Electric Company [Member] | Scenario Adjustment [Member] | ' | ' |
Total interest expense to affiliates, net | $4 | ' |
Variable_Interest_Entities_Det
Variable Interest Entities (Details) (USD $) | 3 Months Ended | 12 Months Ended | 3 Months Ended | ||||||||||||||||||||||||||||||||||||||
In Millions, unless otherwise specified | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | ||||||||||
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] | Investments [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 | 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] | ||||||||||||
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] | ||||||||||||||||||||||||||
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 | $738 | $484 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $679 | $446 | $53 | $28 | ' | ' | ' | ||||||||||
Non Current Assets | 1,893 | 1,905 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,870 | 1,884 | 3 | ' | ' | ' | 3 | ||||||||||
Total Assets | 2,631 | 2,389 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,549 | 2,330 | 56 | 31 | ' | ' | ' | ||||||||||
Current Liabilities | 608 | 566 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 525 | 481 | 78 | 74 | ' | ' | ' | ||||||||||
Non Current Liabilites | 780 | 774 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 566 | 562 | 195 | 195 | ' | ' | ' | ||||||||||
Total Liabilities | 1,388 | 1,340 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,091 | 1,043 | 273 | 269 | ' | ' | ' | ||||||||||
Deferred tax assets | 0 | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | ' | ' | ' | ' | ||||||||||
Remittance of payments received from customers for rate stabilization to BondCo. | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 21 | 22 | ' | ||||||||||
Parental guarantee provided | 75 | 75 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||
Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||
Number of Variable Interest Entities not consolidated by equity holders | 5 | 4 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||
Number Of Variable Interest Entities Consolidated | 8 | 8 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||
Total assets | 457 | [1] | 460 | [1] | ' | 113 | [1] | 128 | [1] | 344 | [1] | 332 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Total liabilities | 141 | [1] | 140 | [1] | ' | 2 | [1] | 17 | [1] | 139 | [1] | 123 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Our ownership interest | 64 | [1] | 86 | [1] | ' | ' | ' | 64 | [1] | 86 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||
Other ownership interests | 254 | [1] | 234 | [1] | ' | 111 | [1] | 111 | [1] | 143 | [1] | 123 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Our maximum exposure to loss | ' | ' | ' | ' | ' | ' | ' | 73 | 74 | 7 | 73 | 67 | 9 | 9 | 9 | 9 | 3 | 5 | 3 | 5 | 44 | [2] | 44 | [2] | 44 | [2] | 44 | [2] | ' | ' | ' | ' | ' | ' | ' | ||||||
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] | 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. | ||||||||||||||||||||||||||||||||||||||||
[2] | 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 $429 million and $458 million as of March 31, 2014 and December 31, 2013, respectively; offset by payables to ZionSolutions LLC of $385 million and $414 million as of March 31, 2014 and December 31, 2013, respectively. These items are included to provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE. |
Regulatory_Matters_Details
Regulatory Matters (Details) (USD $) | 3 Months Ended | 3 Months Ended | 1 Months Ended | 3 Months Ended | 12 Months Ended | 3 Months Ended | 3 Months Ended | 3 Months Ended | 12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Sep. 30, 2008 | Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Feb. 29, 2012 | Dec. 31, 2010 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Jun. 01, 2013 | Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | Sep. 30, 2013 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | |||||||||||||||||||||||||||||||
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 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] | 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] | Regulatory Liabilities Other [Member] | Dlc Program Cost [Member] | Dlc Program Cost [Member] | Energy Efficiency Phase [Member] | Energy Efficiency Phase [Member] | Other Postretirement Benefits [Member] | Other Postretirement Benefits [Member] | Other Postretirement Benefits [Member] | 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 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 Uncollectible Accounts Expense [Member] | Under Recovered Uncollectible Accounts Expense [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] | 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] | Merger Integration Costs [Member] | Merger Integration Costs [Member] | Regulatory Assets [Member] | Regulatory Assets [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] | 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] | Exelon Corporate [Member] | ||||||||||||||||||||||||||||||||||
Regulatory Liabilities Other [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 Energy And Transmission Costs [Member] | Over Recovered Energy And Transmission Costs [Member] | Over-Recovered Universal Service Fund Costs [Member] | Revenue subject to refund [Member] | Revenue subject to refund [Member] | Other Postretirement Benefits [Member] | Deferred Income Taxes [Member] | Deferred Income Taxes [Member] | AMI Expenses [Member] | AMI Expenses [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 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 Uncollectible Accounts Expense [Member] | Under Recovered Uncollectible Accounts Expense [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] | Deferred Storm Costs [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] | Merger Integration Costs [Member] | Regulatory Assets [Member] | Regulatory Assets [Member] | SmartMeters | Nuclear Decommissioning [Member] | Nuclear Decommissioning [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 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] | Gas Distribution Tax Repairs [Member] | Gas Distribution Tax Repairs [Member] | Regulatory Liabilities Other [Member] | Regulatory Liabilities Other [Member] | Dlc Program Cost [Member] | Dlc Program Cost [Member] | Energy Efficiency Phase [Member] | Energy Efficiency Phase [Member] | 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] | Debt Costs [Member] | Debt Costs [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] | Under Recovered Uncollectible Accounts Expense [Member] | Under Recovered Energy And Transmission Costs [Member] | Under Recovered Energy And Transmission 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] | Merger Integration Costs [Member] | Regulatory Assets [Member] | 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 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 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] | 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] | Debt Costs [Member] | Debt Costs [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] | Under Recovered Uncollectible Accounts Expense [Member] | Under Recovered Uncollectible Accounts Expense [Member] | Under Recovered Energy And Transmission Costs [Member] | Under Recovered Energy And Transmission Costs [Member] | Under Recovered Electric Energy And Transmission 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] | Merger Integration Costs [Member] | Merger Integration Costs [Member] | Regulatory Assets [Member] | Regulatory Assets [Member] | Gas Distribution Tax Repairs [Member] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
SmartMeters | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Purchase Of Receivables [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
POR gross receivables | $330,000,000 | [1] | ' | $263,000,000 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $125,000,000 | [1] | ' | $105,000,000 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $93,000,000 | [1] | ' | $72,000,000 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $112,000,000 | [1] | ' | $86,000,000 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||
POR Allowance for uncollectible accounts | -36,000,000 | [2] | ' | -30,000,000 | [2] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -19,000,000 | [2] | ' | -16,000,000 | [2] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -10,000,000 | [2] | ' | -7,000,000 | [2] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -7,000,000 | [2] | ' | -7,000,000 | [2] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||
POR net receivables | 294,000,000 | ' | 233,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 106,000,000 | ' | 89,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 83,000,000 | ' | 65,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 105,000,000 | ' | 79,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Energy Infrastructure Modernization Act [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Current length of state legislation enacted | ' | '10 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Increased revenue requirement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 275,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Expected revenue adjustment for prior year | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 98,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Expected revenue adjustment for current year | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 177,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Excess basis points over treasury after year one | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5.80% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Senate Bill [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Next 6 months Projected Revenue | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 15,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Year 2 Projected Revenue | 65,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Next 12 months Projected CapEx | 40,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Year 2 Projected CapEx | 45,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Next 6 months estimated refund | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 14,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
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 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 396,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 101,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Adjustment to Requested increase in electric revenues | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 343,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Recovery request for Operating and Maintenance expenses of AMI Pilot Program | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 40,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Requested increase in gas revenues | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 30,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
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. | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 143,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 81,000,000 | ' | 34,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Increase in gas delivery service revenue resulting from rate case settlement or order. | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 32,000,000 | ' | 12,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Regulatory Assets Transfer Changes | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Severance Recovered Through Distribution Rates | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
ComEd's proposed increase to net distribution revenue requirement related to uncollectable account expense | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 22,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
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 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 274,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Estimated Refund Obligation To Customers | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 37,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Annual Transmission Formula Rate Update [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Gross transmission revenue requirement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 524,000,000 | 488,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 167,000,000 | ' | 158,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Transmission revenue true up | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 11,000,000 | 25,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,000,000 | ' | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Net transmission revenue requirement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 535,000,000 | 513,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 171,000,000 | ' | 157,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
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 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 595,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Spend on smart grid investments | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 120,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Smart meter spend to date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 457,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Smart grid infrastructure spend to date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 119,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Total smart grid and smart meter investment grant amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 200,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Smart meter investment grant awarded | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 140,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Smart grid investment grant awarded | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 60,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 200,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Reimbursements received from the DOE | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 197,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 200,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Outstanding reimbursable DOE Smart Grid Investment Grant expenditures | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 23,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Regulatory assets for original smart meters purchased | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 17,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Carrying value of originally installed Smart Meters, net of reimbursements from DOE | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 17,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
VendorRefund | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 12,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Amount of reimbursements received from the DOE applied to the originally installed Smart Meters. | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 16,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Total Projected smart meter smart grid spend | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 480,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Current Year AMI Events Balance | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Depreciation Related To Original Meters | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
DOE Cash Payable to Sub Receipients | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Upfront fee for opt-out of Smart Meter | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 75 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
RecurringFees | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 11 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
New Electric Generation [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Megawatt capacity of new generating plant | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 700 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Energy Efficiency Program [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Proposed funding of estimated costs associated with DLC demand program due to modification of incentive levels for other Phase II programs. | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Advanced metering infrastructure pilot program [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Collections Under Rider Amp | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 24,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
RegulatoryLiabilityUnderRiderAmp | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
RefundAMP | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 14,600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Authorized Return On Rate Base [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Weighted Average Debt And Equity Return Electric Distribution | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.07% | 0.07% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Weighted Average Debt And Equity Return | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8.62% | 8.70% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8.53% | 8.35% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
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 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Common Equity Component Cap | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 55.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Regulatory Assets And Liabilities Other Disclosures [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Over under recovered transmission costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 11,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Over under recovered electric supply costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 32,000,000 | ' | 34,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Over under recovered gas supply costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | 16,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Amortization of rate stabilization deferral | 20,000,000 | 30,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20,000,000 | 30,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Recovered portion of regulatory assets | 72,000,000 | 61,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 30,000,000 | 30,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,000,000 | 2,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 38,000,000 | 29,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Maryland Electric And Natural Gas Distribution Rate Cases [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Captial and OM estimates current year | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 14,800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Revenue Requirment | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
License Renewals [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Minimum Purchase Obligation | 20,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Maximum Purchase Obligation | 30,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 30,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
License Costs | 34,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 34,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Regulatory Asset [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 5,863,000,000 | ' | 5,910,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,777,000,000 | 2,794,000,000 | 1,474,000,000 | 1,459,000,000 | 186,000,000 | 159,000,000 | 5,000,000 | 262,000,000 | 285,000,000 | 54,000,000 | 56,000,000 | 206,000,000 | [3] | 219,000,000 | [3] | 0 | [4] | 0 | [4] | 12,000,000 | 12,000,000 | 108,000,000 | 102,000,000 | 201,000,000 | 212,000,000 | 0 | 0 | 74,000,000 | 48,000,000 | 155,000,000 | 176,000,000 | 0 | ' | 2,000,000 | 3,000,000 | 27,000,000 | 30,000,000 | 133,000,000 | 154,000,000 | 146,000,000 | 148,000,000 | 8,000,000 | 9,000,000 | 38,000,000 | 39,000,000 | ' | ' | ' | 918,000,000 | ' | 933,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 67,000,000 | 65,000,000 | 43,000,000 | 35,000,000 | 262,000,000 | 285,000,000 | 51,000,000 | 53,000,000 | 0 | [3] | 0 | [4] | 0 | 0 | 0 | 72,000,000 | 67,000,000 | 168,000,000 | 178,000,000 | 0 | 0 | 74,000,000 | 48,000,000 | 155,000,000 | 176,000,000 | 0 | ' | 0 | 0 | 0 | 0 | 0 | 0 | ' | 26,000,000 | 26,000,000 | 1,465,000,000 | ' | 1,448,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 1,333,000,000 | 1,317,000,000 | 65,000,000 | 58,000,000 | 5,000,000 | 0 | 3,000,000 | 3,000,000 | 0 | [3] | 0 | [4] | ' | 0 | 0 | 25,000,000 | 25,000,000 | 32,000,000 | 33,000,000 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | ' | 7,000,000 | 7,000,000 | ' | ' | 504,000,000 | ' | 524,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 74,000,000 | 77,000,000 | 78,000,000 | 66,000,000 | 0 | 0 | 8,000,000 | 8,000,000 | 0 | [3] | 0 | [4] | ' | 12,000,000 | 12,000,000 | 11,000,000 | 10,000,000 | 1,000,000 | 1,000,000 | 0 | 0 | 0 | 0 | 0 | ' | 2,000,000 | 3,000,000 | 27,000,000 | 30,000,000 | 133,000,000 | 154,000,000 | 146,000,000 | 148,000,000 | 8,000,000 | 9,000,000 | 4,000,000 | 6,000,000 | ' | ||||||||||||||||||||
Current regulatory assets | 768,000,000 | ' | 760,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 218,000,000 | 221,000,000 | 14,000,000 | 10,000,000 | 6,000,000 | 5,000,000 | ' | 197,000,000 | 178,000,000 | 12,000,000 | 12,000,000 | 6,000,000 | [3] | 0 | 9,000,000 | [4] | 12,000,000 | [4] | 10,000,000 | 16,000,000 | 1,000,000 | 1,000,000 | 44,000,000 | 40,000,000 | 2,000,000 | 2,000,000 | 0 | 0 | 13,000,000 | 17,000,000 | 51,000,000 | 53,000,000 | 3,000,000 | 3,000,000 | 13,000,000 | 13,000,000 | 72,000,000 | 71,000,000 | 57,000,000 | 73,000,000 | 2,000,000 | 2,000,000 | 38,000,000 | 31,000,000 | ' | ' | ' | 340,000,000 | ' | 329,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 2,000,000 | 2,000,000 | 6,000,000 | 5,000,000 | 197,000,000 | 178,000,000 | 9,000,000 | 9,000,000 | 0 | [3] | 0 | [4] | 0 | 6,000,000 | 12,000,000 | 1,000,000 | 1,000,000 | 37,000,000 | 33,000,000 | 2,000,000 | 2,000,000 | 0 | 0 | 13,000,000 | 17,000,000 | 50,000,000 | 52,000,000 | 0 | 0 | 0 | ' | 0 | 0 | 0 | 17,000,000 | 18,000,000 | 28,000,000 | ' | 17,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | 0 | ' | ' | 0 | 3,000,000 | 3,000,000 | 0 | [3] | 0 | [4] | 0 | 0 | 0 | 0 | 0 | 6,000,000 | 6,000,000 | 0 | 0 | 1,000,000 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 18,000,000 | 8,000,000 | ' | ' | 168,000,000 | ' | 181,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 12,000,000 | 8,000,000 | 0 | 0 | 0 | 0 | 1,000,000 | 1,000,000 | 0 | [3] | 1,000,000 | 11,000,000 | 4,000,000 | 4,000,000 | 0 | ' | 1,000,000 | 1,000,000 | 0 | 0 | 0 | 0 | 1,000,000 | [5] | 7,000,000 | 3,000,000 | 3,000,000 | 13,000,000 | 13,000,000 | 72,000,000 | 71,000,000 | 57,000,000 | 73,000,000 | 2,000,000 | 2,000,000 | 3,000,000 | 4,000,000 | ' | |||||||||||||||||||||
Net regulatory asset | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 459,000,000 | 463,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Regulatory Liabilities [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Regulatory Liability Current | 336,000,000 | ' | 327,000,000 | ' | 0 | 105,000,000 | 99,000,000 | 40,000,000 | 53,000,000 | 22,000,000 | 20,000,000 | 76,000,000 | 78,000,000 | 7,000,000 | 8,000,000 | 38,000,000 | [6] | 38,000,000 | [6] | 35,000,000 | [7] | 16,000,000 | [7] | 8,000,000 | 2,000,000 | 4,000,000 | 1,000,000 | 1,000,000 | ' | ' | 2,000,000 | 2,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 158,000,000 | ' | 170,000,000 | ' | ' | ' | ' | 0 | 81,000,000 | 78,000,000 | 39,000,000 | 45,000,000 | 0 | 0 | 9,000,000 | 0 | 38,000,000 | [6] | 38,000,000 | [6] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 84,000,000 | ' | 106,000,000 | ' | 0 | 0 | 1,000,000 | 8,000,000 | 22,000,000 | 20,000,000 | 43,000,000 | [8] | 58,000,000 | [8] | 7,000,000 | 8,000,000 | 8,000,000 | 8,000,000 | 2,000,000 | 3,000,000 | 1,000,000 | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 92,000,000 | ' | 48,000,000 | ' | 0 | 24,000,000 | 21,000,000 | 0 | 0 | 33,000,000 | [5] | 11,000,000 | 30,000,000 | 0 | 35,000,000 | [7] | 16,000,000 | [7] | 14,000,000 | 21,000,000 | 9,000,000 | 0 | 3,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8,000,000 | |||||||||||||||||||
Noncurrent regulatory liabilities | 4,458,000,000 | ' | 4,388,000,000 | 2,774,000,000 | 2,740,000,000 | 1,440,000,000 | 1,423,000,000 | ' | 0 | 108,000,000 | 114,000,000 | 10,000,000 | 0 | ' | 0 | ' | ' | ' | ' | 37,000,000 | 1,000,000 | ' | 11,000,000 | 10,000,000 | 31,000,000 | 21,000,000 | 47,000,000 | 43,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | 3,566,000,000 | ' | 3,512,000,000 | ' | ' | ' | 2,319,000,000 | 2,293,000,000 | 1,237,000,000 | 1,219,000,000 | 0 | 0 | 0 | 10,000,000 | 0 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 641,000,000 | ' | 629,000,000 | 455,000,000 | 447,000,000 | 0 | ' | 0 | 108,000,000 | 114,000,000 | ' | 0 | ' | 0 | 36,000,000 | 37,000,000 | ' | ' | 11,000,000 | 10,000,000 | 31,000,000 | 21,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 203,000,000 | ' | 204,000,000 | ' | 0 | 203,000,000 | 204,000,000 | 0 | 0 | ' | 0 | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 36,000,000 | ||||||||||||||||||||||||||||||
Regulatory Liabilities Table Footnote Data [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
Electric Transmission Costs Under-Recovery | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $8,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||
[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 8 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] | . Relates to $3 million of over-recovered electric supply costs and $30 million of over-recovered natural gas supply costs as of March 31, 2014. As of December 31, 2013, includes $1 million of under-recovered electric supply costs and $11 million of over-recovered natural gas supply costs. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[6] | Primarily represents the regulatory liability for revenue subject to refund recorded pursuant to the ICCbs order in the 2007 Rate Case. See Note 3 b Regulatory Matters of the Exelon 2013 Form 10-K. for further information. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[7] | Represents the electric and gas distribution costs recoverable from customers under BGEbs decoupling mechanism. As of March 31, 2014, BGE had a regulatory liability of $14 million related to over-recovered electric revenue decoupling and $21 million related to over-recovered natural gas revenue decoupling. As of December 31, 2013, BGE had a regulatory liability of $7 million related to over-recovered electric revenue decoupling and $9 million related to over-recovered natural gas revenue decoupling | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[8] | Includes $32 million related to the DSP program, $0 million related to the over-recovered natural gas costs under the PGC and $11 million related to over-recovered electric transmission costs as of March 31, 2014. As of December 31, 2013, includes $34 million related to the DSP program, $8 million related to the over-recovered electric transmission costs and $16 million related to the over-recovered natural gas costs under the PGC. |
Merger_and_Acquisitions_Detail
Merger and Acquisitions (Details) (USD $) | 3 Months Ended | ||||
Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2012 | |||
Business Acquisition, Impact Of Merger [Abstract] | ' | ' | ' | ||
Revenues | $7,237,000,000 | [1] | $6,082,000,000 | [1] | ' |
Net income | 93,000,000 | 1,000,000 | ' | ||
Business Acquisition, Regulatory Matters [Abstract] | ' | ' | ' | ||
Business Acquisition Potential Cash Payment | 40,000,000 | ' | ' | ||
Restructuring Reserve [Roll Forward] | ' | ' | ' | ||
Restructuring Reserve, Period Start | 53,000,000 | ' | ' | ||
Payments | 12,000,000 | ' | ' | ||
Restructuring Reserve, Period End | 41,000,000 | ' | ' | ||
Business Acquisition, Costs Recognized Post Merger [Abstract] | ' | ' | ' | ||
Length of years for charitable contributions at $7 million per year | '10 years | ' | ' | ||
Business Acquisition Charitable Contributions Per Year | 7,000,000 | ' | ' | ||
Exelon Generation Co L L C [Member] | ' | ' | ' | ||
Business Acquisition, Impact Of Merger [Abstract] | ' | ' | ' | ||
Revenues | 4,390,000,000 | 3,533,000,000 | ' | ||
Net income | -185,000,000 | -17,000,000 | ' | ||
Restructuring Reserve [Roll Forward] | ' | ' | ' | ||
Restructuring Reserve, Period Start | 10,000,000 | ' | ' | ||
Payments | 1,000,000 | ' | ' | ||
Restructuring Reserve, Period End | 9,000,000 | ' | ' | ||
Exelon Generation Co L L C [Member] | Minimum [Member] | ' | ' | ' | ||
Business Acquisition, Regulatory Matters [Abstract] | ' | ' | ' | ||
Business Acquisition, Construction Cost | ' | 95,000,000 | ' | ||
Business Acquisition, Development Of New Generation Cost | 600,000,000 | ' | ' | ||
Business Acquisition, Expected New Generation Mwh | 285 | ' | ' | ||
Exelon Generation Co L L C [Member] | Maximum [Member] | ' | ' | ' | ||
Business Acquisition, Regulatory Matters [Abstract] | ' | ' | ' | ||
Business Acquisition, Construction Cost | ' | 120,000,000 | ' | ||
Business Acquisition, Development Of New Generation Cost | 650,000,000 | ' | ' | ||
Business Acquisition, Expected New Generation Mwh | 300 | ' | ' | ||
Commonwealth Edison Co [Member] | ' | ' | ' | ||
Business Acquisition, Impact Of Merger [Abstract] | ' | ' | ' | ||
Revenues | 1,134,000,000 | 1,160,000,000 | ' | ||
Net income | 98,000,000 | -81,000,000 | ' | ||
Restructuring Reserve [Roll Forward] | ' | ' | ' | ||
Restructuring Reserve, Period Start | 0 | ' | ' | ||
Payments | 0 | ' | ' | ||
Restructuring Reserve, Period End | 0 | ' | ' | ||
PECO Energy Co [Member] | ' | ' | ' | ||
Business Acquisition, Impact Of Merger [Abstract] | ' | ' | ' | ||
Revenues | 993,000,000 | 895,000,000 | ' | ||
Net income | 89,000,000 | 122,000,000 | ' | ||
Restructuring Reserve [Roll Forward] | ' | ' | ' | ||
Restructuring Reserve, Period Start | 0 | ' | ' | ||
Payments | 0 | ' | ' | ||
Restructuring Reserve, Period End | 0 | ' | ' | ||
Baltimore Gas and Electric Company [Member] | ' | ' | ' | ||
Business Acquisition, Impact Of Merger [Abstract] | ' | ' | ' | ||
Revenues | 1,054,000,000 | 880,000,000 | ' | ||
Net income | 88,000,000 | 80,000,000 | ' | ||
Regulatory Assets Transfer Changes | 8,000,000 | ' | ' | ||
Business Acquisition, Regulatory Matters [Abstract] | ' | ' | ' | ||
Business Acquisition, Direct Investment With State And Local Governments Due To Settlement | ' | ' | 1,000,000,000 | ||
Restructuring Reserve [Roll Forward] | ' | ' | ' | ||
Restructuring Reserve, Period Start | 6,000,000 | ' | ' | ||
Payments | 2,000,000 | ' | ' | ||
Restructuring Reserve, Period End | $4,000,000 | ' | ' | ||
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 | ' | ' | ||
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 | ' | ' | ||
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 | ' | ' | ||
[1] | For the ##D<curmonth> months ended ##D<cyperiod> and ##D<pyfiscal>, utility taxes of $##D<gcytdutiltax> million and $##D<gpytdutiltax> million, respectively, are included in revenues and expenses for Generation. For the ##D<curmonth> months ended ##D<cyperiod> and ##D<pyfiscal>, utility taxes of $##D<ccytdutiltax> million and $##D<cpytdutiltax> million, respectively, are included in revenues and expenses for ComEd. For the ##D<curmonth> months ended ##D<cyperiod> and ##D<pyfiscal>, utility taxes of $##D<pcytdutiltax> million and $##D<ppytdutiltax> million, respectively, are included in revenues and expenses for PECO. For the ##D<curmonth> months ended ##D<cyperiod> and period of March 12, 2012 through ##D<pyperiod>, utility taxes of $##D<bcytdutiltax> million and $##D<bpytdutiltax> million, respectively, are included in revenues and expenses for BGE. |
Investment_in_Constellation_En2
Investment in Constellation Energy Nuclear Group, LLC (Details) (USD $) | 3 Months Ended | 3 Months Ended | 12 Months Ended | 3 Months Ended | 0 Months Ended | |||||||||||||||||
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 | Apr. 02, 2014 | Apr. 02, 2014 | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2013 | Apr. 02, 2014 | Apr. 02, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2013 | Apr. 02, 2014 | Apr. 02, 2014 | Apr. 02, 2014 | ||||
CENG [Member] | CENG [Member] | Constellation Energy Nuclear Group [Member] | Constellation Energy Nuclear Group [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Constellation Energy Group LLC [Member] | Constellation Energy Group LLC [Member] | Electricite De France LLC [Member] | |||||||
Subsequent Event [Member] | Subsequent Event [Member] | CENG [Member] | CENG [Member] | First Distribution [Member] | Second Distribution [Member] | Minimum [Member] | Constellation Energy Nuclear Group [Member] | Constellation Energy Nuclear Group [Member] | EDFI [Member] | GenerationCoMember [Member] | CENG [Member] | |||||||||||
FinancialGuaranteeMember | Payment Guarantee [Member] | Subsequent Event [Member] | Subsequent Event [Member] | CENG [Member] | CENG [Member] | Subsequent Event [Member] | Subsequent Event [Member] | Subsequent Event [Member] | ||||||||||||||
Payment Guarantee [Member] | FinancialGuaranteeMember | |||||||||||||||||||||
Schedule of Equity Method Investments [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Percentage of ownership interest in CENG (as a percent) | ' | ' | ' | ' | ' | ' | 50.01% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
CENG | ' | ' | ' | ' | $93 | $53 | ' | ' | ' | ' | ' | ' | ' | ($2) | $15 | ' | ' | ' | ||||
Amortization of basis difference in CENG | ' | ' | ' | ' | -88 | -131 | ' | ' | ' | ' | ' | ' | ' | -17 | -27 | ' | ' | ' | ||||
Total equity investment earnings (losses) - CENG | ' | ' | ' | ' | 5 | -78 | ' | ' | ' | ' | ' | ' | ' | -19 | -12 | ' | ' | ' | ||||
Basis difference in investment in CENG | ' | ' | ' | ' | ' | ' | 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 | ' | ' | ' | ' | ' | ' | 334 | 392 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Amortization of energy contract assets and liabilities | 42 | [1] | 176 | [1] | ' | ' | ' | ' | 44 | [1] | 176 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution From Affiliates | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 115 | 13 | ' | ' | ' | ' | ' | ' | ||||
Loan Recievable from CENG | ' | ' | ' | ' | ' | ' | ' | ' | 400 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Special and Preferred Distributions by CENG | ' | ' | ' | ' | ' | ' | 30 | 211 | ' | ' | ' | ' | ' | ' | ' | 400 | 400 | ' | ||||
Debt Instrument Interest Rate Stated Percentage | ' | ' | ' | ' | ' | ' | ' | ' | 5.25% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
InterestRateOnDistribution | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8.50% | ' | ||||
Maximum exposure related to guarantees | 9,890 | ' | ' | ' | ' | ' | 6,491 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 145 | ||||
Due To Affiliate Current And Noncurrent | ' | ' | $165 | $245 | ' | ' | ' | ' | ' | $205 | ' | ' | ' | ' | ' | ' | ' | ' | ||||
[1] | Included in Operating revenues or Purchased power and fuel expense on the Registrants' Consolidated Statements of Operations and Comprehensive Income. |
Impairment_of_LongLived_Assets
Impairment of Long-Lived Assets (Details) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 |
Capital Leases, Net Investment in Direct Financing Leases [Abstract] | ' | ' |
Capital Leases, Net Investment in Direct Financing Leases, Unguaranteed Residual Values of Leased Property | $731,000,000 | $1,465,000,000 |
Less: unearned income | -363,000,000 | -767,000,000 |
Net investment in long-term leases | 368,000,000 | 698,000,000 |
CapitalLeaseNetInvestmentInDirectFinancingLeasesPrepaymentsReceived | $1,200,000,000 | ' |
Goodwill_Details
Goodwill (Details) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Goodwill [Roll Forward] | ' | ' |
Goodwill, beginning balance | $2,625 | $2,625 |
Goodwill, ending balance | 2,625 | 2,625 |
Exelon Generation Co L L C [Member] | ' | ' |
Goodwill [Roll Forward] | ' | ' |
Goodwill, beginning balance | 0 | 0 |
Goodwill, ending balance | 0 | 0 |
Commonwealth Edison Co [Member] | ' | ' |
Goodwill [Roll Forward] | ' | ' |
Goodwill, beginning balance | 2,625 | 2,625 |
Goodwill, ending balance | $2,625 | $2,625 |
Accounts_Receivable_Details
Accounts Receivable (Details) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Accounts Notes And Loans Receivable Net Current [Abstract] | ' | ' |
Allowance for uncollectible accounts | $306 | $272 |
Accounts Receivable Additional Disclosures [Abstract] | ' | ' |
Gross Accounts Receivable Pledged as Collateral | 0 | 0 |
Exelon Generation Co L L C [Member] | ' | ' |
Accounts Notes And Loans Receivable Net Current [Abstract] | ' | ' |
Allowance for uncollectible accounts | 46 | 57 |
Commonwealth Edison Co [Member] | ' | ' |
Accounts Notes And Loans Receivable Net Current [Abstract] | ' | ' |
Allowance for uncollectible accounts | 76 | 62 |
PECO Energy Co [Member] | ' | ' |
Accounts Notes And Loans Receivable Net Current [Abstract] | ' | ' |
Allowance for uncollectible accounts | 140 | 107 |
Accounts Receivable Additional Disclosures [Abstract] | ' | ' |
Gross Accounts Receivable Pledged as Collateral | 0 | 0 |
Financing Receivable Recorded Investment [Line Items] | ' | ' |
Installment plan receivables | 18 | 19 |
Installment plan receivables uncollectible accounts reserve | -15 | -18 |
PECO Energy Co [Member] | Medium Risk [Member] | ' | ' |
Financing Receivable Recorded Investment [Line Items] | ' | ' |
Installment plan receivables uncollectible accounts reserve | -4 | -4 |
PECO Energy Co [Member] | High Risk [Member] | ' | ' |
Financing Receivable Recorded Investment [Line Items] | ' | ' |
Installment plan receivables uncollectible accounts reserve | -10 | -13 |
Baltimore Gas and Electric Company [Member] | ' | ' |
Accounts Notes And Loans Receivable Net Current [Abstract] | ' | ' |
Allowance for uncollectible accounts | $44 | $46 |
Property_Plant_and_Equipment_D
Property, Plant and Equipment (Details) (USD $) | 3 Months Ended | |||
In Millions, unless otherwise specified | Mar. 31, 2014 | Dec. 31, 2013 | ||
Property Plant And Equipment [Line Items] | ' | ' | ||
Less: accumulated depreciation | ($14,066) | [1] | ($13,713) | [2] |
Property, plant and equipment, net | 47,742 | 47,330 | ||
Property Plant And Equipment Footnotes [Abstract] | ' | ' | ||
Accumulated amortization of nuclear fuel | 2,425 | 2,371 | ||
Plant Retirement Cost [Abstract] | ' | ' | ||
Inventory write down related to plant retirements | 2 | ' | ||
Exelon Generation Co L L C [Member] | ' | ' | ||
Property Plant And Equipment [Line Items] | ' | ' | ||
Less: accumulated depreciation | -7,245 | [1] | -7,034 | [2] |
Property, plant and equipment, net | 20,132 | 20,111 | ||
Property Plant And Equipment Footnotes [Abstract] | ' | ' | ||
Accumulated amortization of nuclear fuel | 2,425 | 2,371 | ||
Plant Retirement Cost [Abstract] | ' | ' | ||
Inventory write down related to plant retirements | 2 | ' | ||
Commonwealth Edison Co [Member] | ' | ' | ||
Property Plant And Equipment [Line Items] | ' | ' | ||
Less: accumulated depreciation | -3,247 | -3,184 | ||
Property, plant and equipment, net | 14,890 | 14,666 | ||
PECO Energy Co [Member] | ' | ' | ||
Property Plant And Equipment [Line Items] | ' | ' | ||
Less: accumulated depreciation | -2,958 | -2,935 | ||
Property, plant and equipment, net | 6,480 | 6,384 | ||
Baltimore Gas and Electric Company [Member] | ' | ' | ||
Property Plant And Equipment [Line Items] | ' | ' | ||
Less: accumulated depreciation | -2,741 | -2,702 | ||
Property, plant and equipment, net | $5,939 | $5,864 | ||
[1] | Includes accumulated amortization of nuclear fuel in the reactor core of $2,425 million. | |||
[2] | Includes accumulated amortization of nuclear fuel in the reactor core of $2,371 million. |
Fair_Value_of_Financial_Assets3
Fair Value of Financial Assets and Liabilities (Fair Value By Balance Sheet Grouping) (Details) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Carrying Reported Amount Fair Value Disclosure [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | $983 | $344 |
Long-term debt (including amounts due within one year) | 18,920 | 19,132 |
Long-term debt to financing trusts | 648 | 648 |
Spent nuclear fuel obligation | 1,021 | 1,021 |
Preferred securities of subsidiary | ' | 0 |
Estimate Of Fair Value Fair Value Disclosure [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | 983 | 344 |
Long-term debt (including amounts due within one year) | 20,042 | 19,751 |
Long-term debt to financing trusts | 648 | 631 |
Spent nuclear fuel obligation | 840 | 790 |
Preferred securities of subsidiary | ' | 0 |
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 | 3 |
Estimate Of Fair Value Fair Value Disclosure [Member] | Fair Value Inputs Level 2 [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | 980 | 341 |
Long-term debt (including amounts due within one year) | 18,976 | 18,672 |
Spent nuclear fuel obligation | 840 | 790 |
Preferred securities of subsidiary | ' | 0 |
Estimate Of Fair Value Fair Value Disclosure [Member] | Fair Value Inputs Level 3 [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Long-term debt (including amounts due within one year) | 1,066 | 1,079 |
Long-term debt to financing trusts | 648 | 631 |
Exelon Generation Co L L C [Member] | Carrying Reported Amount Fair Value Disclosure [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | 377 | 22 |
Long-term debt (including amounts due within one year) | 7,490 | 7,729 |
Spent nuclear fuel obligation | 1,021 | 1,021 |
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 | 377 | 22 |
Long-term debt (including amounts due within one year) | 7,750 | 7,648 |
Spent nuclear fuel obligation | 840 | 790 |
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 | 377 | 22 |
Long-term debt (including amounts due within one year) | 6,684 | 6,586 |
Spent nuclear fuel obligation | 840 | 790 |
Exelon Generation Co L L C [Member] | Estimate Of Fair Value Fair Value Disclosure [Member] | Fair Value Inputs Level 3 [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Long-term debt (including amounts due within one year) | 1,066 | 1,062 |
Commonwealth Edison Co [Member] | Carrying Reported Amount Fair Value Disclosure [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | 534 | 184 |
Long-term debt (including amounts due within one year) | 5,707 | 5,675 |
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 | 534 | 184 |
Long-term debt (including amounts due within one year) | 6,347 | 6,255 |
Long-term debt to financing trusts | 202 | 202 |
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 | 534 | 184 |
Long-term debt (including amounts due within one year) | 6,347 | 6,238 |
Commonwealth Edison Co [Member] | Estimate Of Fair Value Fair Value Disclosure [Member] | Fair Value Inputs Level 3 [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Long-term debt (including amounts due within one year) | 0 | 17 |
Long-term debt to financing trusts | 202 | 202 |
PECO Energy Co [Member] | Carrying Reported Amount Fair Value Disclosure [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | 0 | 0 |
Long-term debt (including amounts due within one year) | 2,197 | 2,197 |
Long-term debt to financing trusts | 184 | 184 |
PECO Energy Co [Member] | Estimate Of Fair Value Fair Value Disclosure [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | 0 | 0 |
Long-term debt (including amounts due within one year) | 2,392 | 2,358 |
Long-term debt to financing trusts | 190 | 180 |
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 | 0 |
Long-term debt (including amounts due within one year) | 2,392 | 2,358 |
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 | 190 | 180 |
Baltimore Gas and Electric Company [Member] | Carrying Reported Amount Fair Value Disclosure [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | 72 | 138 |
Long-term debt (including amounts due within one year) | 2,011 | 2,011 |
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 | 72 | 138 |
Long-term debt (including amounts due within one year) | 2,183 | 2,148 |
Long-term debt to financing trusts | 256 | 249 |
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 | 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 | 69 | 135 |
Long-term debt (including amounts due within one year) | 2,183 | 2,148 |
Baltimore Gas and Electric Company [Member] | Estimate Of Fair Value Fair Value Disclosure [Member] | Fair Value Inputs Level 3 [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Long-term debt to financing trusts | $256 | $249 |
Fair_Value_of_Financial_Assets4
Fair Value of Financial Assets and Liabilities (Fair Value Measurements, Recurring and Nonrecurring) (Details) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2013 | ||
In Millions, unless otherwise specified | |||||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | $518 | [1] | $1,230 | [1] | ' |
Fixed income [Abstract] | ' | ' | ' | ||
Other investments | 23 | 15 | ' | ||
Deferred compensation | -107 | -114 | ' | ||
Total assets | 10,525 | 11,162 | ' | ||
Total liabilities | -645 | -573 | ' | ||
Total net assets | 9,880 | 10,589 | ' | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Deferred compensation | 107 | 114 | ' | ||
Mark-to-market derivative liabilities (current liabilities) | 251 | 159 | ' | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | 287 | 300 | ' | ||
Nuclear Decommissioning Trust Fund Investments [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 304 | 459 | ' | ||
Equity Securities [Abstract] | ' | ' | ' | ||
Equity securities | 1,813 | 1,776 | ' | ||
Exchange traded funds | 113 | 115 | ' | ||
Commingled funds | 2,053 | 2,271 | ' | ||
Equity securities subtotal | 3,979 | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 903 | 882 | ' | ||
Debt securities issued by states of the United States and political subdivisions of the states | 295 | 294 | ' | ||
Debt securities issued by foreign governments | 87 | 87 | ' | ||
Corporate debt securities | 1,921 | 1,784 | ' | ||
Federal agency mortgage-backed securities | 9 | 10 | ' | ||
Commercial mortgage-backed securities (non-agency) | 40 | 40 | ' | ||
Residential mortgage-backed securities (non-agency) | 7 | 7 | ' | ||
Mutual funds fixed income | 278 | 18 | ' | ||
Fixed income subtotal | 3,540 | 3,122 | ' | ||
Private equity | 4 | 5 | ' | ||
Direct lending securities | 356 | 314 | ' | ||
Other debt obligations | 15 | 14 | ' | ||
Nuclear decommissioning trust fund investments subtotal | 8,198 | [2] | 8,076 | [2] | ' |
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Net assets (liabilities) excluded from nuclear decommissioning trust fund investments | 17 | -5 | ' | ||
Pledged Assets For Zion Station Decommissioning [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 35 | 26 | ' | ||
Equity Securities [Abstract] | ' | ' | ' | ||
Equity securities | 5 | 16 | ' | ||
Equity securities subtotal | 5 | 16 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 40 | 49 | ' | ||
Debt securities issued by states of the United States and political subdivisions of the states | 18 | 20 | ' | ||
Corporate debt securities | 180 | 227 | ' | ||
Fixed income subtotal | 238 | 296 | ' | ||
Direct lending securities | 137 | 112 | ' | ||
Other debt obligations | ' | 1 | ' | ||
Pledged assets for Zion Station decommissioning subtotal | 415 | [3] | 451 | [3] | ' |
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Net assets (liabilities) excluded from pledged assets | 14 | 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 | 42 | [4],[5] | 54 | [4],[5] | ' |
Rabbi trust investments subtotal | 44 | 56 | ' | ||
Deferred compensation | -41 | -53 | ' | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Deferred compensation | 41 | 53 | ' | ||
Supplemental executive retirement plan fair value | 1 | 1 | ' | ||
Cash surrender value of life insurance investments excluded from Rabbi Trust investments | 33 | 32 | ' | ||
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 | 13 | 17 | ' | ||
Fair value of energy swap contract noncurrent liability | 155 | 176 | ' | ||
Commodity Mark To Market Derivative Assets [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Other derivatives | 4,641 | 3,960 | ' | ||
Proprietary trading | 1,341 | 1,761 | ' | ||
Effect of netting and allocation of collateral received/(paid) | -4,694 | [6] | -4,424 | [6] | ' |
Mark-to-market subtotal | 1,288 | 1,297 | ' | ||
Commodity Mark To Market Derivative Liabilities [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Other derivatives | -4,463 | -3,020 | ' | ||
Proprietary trading | -1,318 | -1,703 | ' | ||
Effect of netting and allocation of collateral received/(paid) | 5,261 | [6] | 4,280 | [6] | ' |
Mark-to-market subtotal | -520 | -443 | ' | ||
Interest Rate Mark To Market Derivative Assets [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Effect of netting and allocation of collateral received/(paid) | -22 | 32 | ' | ||
Interest rate mark to market | 61 | 69 | ' | ||
Interest rate mark-to-market Subtotal | 39 | 37 | ' | ||
Interest Rate Mark To Market Derivative Liabilities [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Effect of netting and allocation of collateral received/(paid) | -28 | 32 | ' | ||
Interest rate mark to market | -46 | 48 | ' | ||
Interest rate mark-to-market Subtotal | -18 | 16 | ' | ||
Fair Value Inputs Level 1 [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 518 | [1] | 1,230 | [1] | ' |
Fixed income [Abstract] | ' | ' | ' | ||
Effect of netting and allocation of collateral received/(paid) | ' | -31 | ' | ||
Other investments | 13 | 0 | ' | ||
Deferred compensation | 0 | 0 | ' | ||
Total assets | 3,874 | 4,533 | ' | ||
Total liabilities | 0 | 1 | ' | ||
Total net assets | 3,874 | 4,534 | ' | ||
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 | 117 | 6 | ' | ||
Fair Value Inputs Level 1 [Member] | Nuclear Decommissioning Trust Fund Investments [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 304 | 459 | ' | ||
Equity Securities [Abstract] | ' | ' | ' | ||
Equity securities | 1,813 | 1,776 | ' | ||
Exchange traded funds | 113 | 115 | ' | ||
Commingled funds | 0 | ' | ' | ||
Equity securities subtotal | 1,926 | 1,891 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 903 | 882 | ' | ||
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 | 903 | 882 | ' | ||
Direct lending securities | 0 | ' | ' | ||
Other debt obligations | 0 | ' | ' | ||
Nuclear decommissioning trust fund investments subtotal | 3,133 | [2] | 3,232 | [2] | ' |
Fair Value Inputs Level 1 [Member] | Pledged Assets For Zion Station Decommissioning [Member] | ' | ' | ' | ||
Equity Securities [Abstract] | ' | ' | ' | ||
Equity securities | 4 | 16 | ' | ||
Equity securities subtotal | 4 | 16 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 36 | 45 | ' | ||
Debt securities issued by states of the United States and political subdivisions of the states | 0 | ' | ' | ||
Corporate debt securities | 0 | ' | ' | ||
Fixed income subtotal | 36 | 45 | ' | ||
Direct lending securities | 0 | ' | ' | ||
Pledged assets for Zion Station decommissioning subtotal | 40 | [3] | 61 | [3] | ' |
Fair Value Inputs Level 1 [Member] | Rabbi Trust Investments [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 2 | 2 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Mutual funds | 42 | [4],[5] | 54 | [4],[5] | ' |
Rabbi trust investments subtotal | 44 | 56 | ' | ||
Fair Value Inputs Level 1 [Member] | Commodity Mark To Market Derivative Assets [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Other derivatives | 592 | 493 | ' | ||
Proprietary trading | 354 | 324 | ' | ||
Effect of netting and allocation of collateral received/(paid) | -826 | [6] | -863 | [6] | ' |
Mark-to-market subtotal | 120 | -46 | ' | ||
Fair Value Inputs Level 1 [Member] | Commodity Mark To Market Derivative Liabilities [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Other derivatives | -586 | -540 | ' | ||
Proprietary trading | -357 | -328 | ' | ||
Effect of netting and allocation of collateral received/(paid) | 943 | [6] | 869 | [6] | ' |
Mark-to-market subtotal | 0 | 1 | ' | ||
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) | -18 | -30 | ' | ||
Interest rate mark to market | 24 | 30 | ' | ||
Interest rate mark-to-market Subtotal | 6 | 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) | 25 | ' | ' | ||
Interest rate mark to market | -25 | ' | 31 | ||
Interest rate mark-to-market Subtotal | 0 | 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 | -107 | -114 | ' | ||
Total assets | 5,479 | 5,575 | ' | ||
Total liabilities | -225 | -269 | ' | ||
Total net assets | 5,254 | 5,306 | ' | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Deferred compensation | 107 | 114 | ' | ||
Collateral received from counterparties, net of collateral paid to counterparties | 332 | -124 | ' | ||
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 | 2,053 | 2,271 | ' | ||
Equity securities subtotal | 2,053 | 2,271 | ' | ||
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 | 294 | ' | ||
Debt securities issued by foreign governments | 87 | 87 | ' | ||
Corporate debt securities | 1,795 | 1,753 | ' | ||
Federal agency mortgage-backed securities | 9 | 10 | ' | ||
Commercial mortgage-backed securities (non-agency) | 40 | 40 | ' | ||
Residential mortgage-backed securities (non-agency) | 7 | 7 | ' | ||
Mutual funds fixed income | 278 | 18 | ' | ||
Fixed income subtotal | 2,511 | 2,209 | ' | ||
Direct lending securities | 0 | ' | ' | ||
Other debt obligations | 15 | 14 | ' | ||
Nuclear decommissioning trust fund investments subtotal | 4,579 | [2] | 4,494 | [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 | 35 | 26 | ' | ||
Equity Securities [Abstract] | ' | ' | ' | ||
Equity securities | 1 | ' | ' | ||
Equity securities subtotal | 1 | 0 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 4 | 4 | ' | ||
Debt securities issued by states of the United States and political subdivisions of the states | 18 | 20 | ' | ||
Corporate debt securities | 180 | 227 | ' | ||
Fixed income subtotal | 202 | 251 | ' | ||
Direct lending securities | 0 | ' | ' | ||
Other debt obligations | ' | 1 | ' | ||
Pledged assets for Zion Station decommissioning subtotal | 238 | [3] | 278 | [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 | 2,778 | 2,582 | ' | ||
Proprietary trading | 808 | 1,315 | ' | ||
Effect of netting and allocation of collateral received/(paid) | -2,957 | [6] | -3,131 | [6] | ' |
Mark-to-market subtotal | 629 | 766 | ' | ||
Fair Value Inputs Level 2 [Member] | Commodity Mark To Market Derivative Liabilities [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Other derivatives | -2,624 | -1,890 | ' | ||
Proprietary trading | -765 | -1,256 | ' | ||
Effect of netting and allocation of collateral received/(paid) | 3,289 | [6] | 3,007 | [6] | ' |
Mark-to-market subtotal | -100 | -139 | ' | ||
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) | -4 | 2 | ' | ||
Interest rate mark to market | 37 | 39 | ' | ||
Interest rate mark-to-market Subtotal | 33 | 37 | ' | ||
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) | -3 | -1 | ' | ||
Interest rate mark to market | -21 | 17 | ' | ||
Interest rate mark-to-market Subtotal | -18 | 16 | ' | ||
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] | ' | ' | ' | ||
Other investments | 10 | 15 | ' | ||
Deferred compensation | 0 | 0 | ' | ||
Total assets | 1,172 | 1,054 | ' | ||
Total liabilities | -420 | -305 | ' | ||
Total net assets | 752 | 749 | ' | ||
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 | 118 | -26 | ' | ||
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 | 126 | 31 | ' | ||
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 | 126 | 31 | ' | ||
Private equity | 4 | 5 | ' | ||
Direct lending securities | 356 | 314 | ' | ||
Other debt obligations | 0 | ' | ' | ||
Nuclear decommissioning trust fund investments subtotal | 486 | [2] | 350 | [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 | ' | ' | ||
Fixed income subtotal | 0 | 0 | ' | ||
Direct lending securities | 137 | 112 | ' | ||
Pledged assets for Zion Station decommissioning subtotal | 137 | [3] | 112 | [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 | 1,271 | 885 | ' | ||
Proprietary trading | 179 | 122 | ' | ||
Effect of netting and allocation of collateral received/(paid) | -911 | [6] | -430 | [6] | ' |
Mark-to-market subtotal | 539 | 577 | ' | ||
Fair Value Inputs Level 3 [Member] | Commodity Mark To Market Derivative Liabilities [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Other derivatives | -1,253 | -590 | ' | ||
Proprietary trading | -196 | -119 | ' | ||
Effect of netting and allocation of collateral received/(paid) | 1,029 | [6] | 404 | [6] | ' |
Mark-to-market subtotal | -420 | -305 | ' | ||
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 | 329 | 1,006 | [1] | ' | |
Fixed income [Abstract] | ' | ' | ' | ||
Other investments | 23 | 15 | ' | ||
Deferred compensation | -29 | -29 | ' | ||
Total assets | 10,296 | 10,888 | ' | ||
Total liabilities | -398 | -291 | ' | ||
Total net assets | 9,898 | 10,597 | ' | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Deferred compensation | 29 | 29 | ' | ||
Mark-to-market derivative liabilities (current liabilities) | 238 | 142 | ' | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | 131 | 120 | ' | ||
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 | 304 | 459 | ' | ||
Equity Securities [Abstract] | ' | ' | ' | ||
Equity securities | 1,813 | 1,776 | ' | ||
Exchange traded funds | 113 | 115 | ' | ||
Commingled funds | 2,053 | 2,271 | ' | ||
Equity securities subtotal | 3,979 | 4,162 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 903 | 882 | ' | ||
Debt securities issued by states of the United States and political subdivisions of the states | 295 | 294 | ' | ||
Debt securities issued by foreign governments | 87 | 87 | ' | ||
Corporate debt securities | 1,921 | 1,784 | ' | ||
Federal agency mortgage-backed securities | 9 | 10 | ' | ||
Commercial mortgage-backed securities (non-agency) | 40 | 40 | ' | ||
Residential mortgage-backed securities (non-agency) | 7 | 7 | ' | ||
Mutual funds fixed income | 278 | 18 | ' | ||
Fixed income subtotal | 3,540 | 3,122 | ' | ||
Private equity | 4 | 5 | ' | ||
Direct lending securities | 356 | 314 | ' | ||
Other debt obligations | 15 | 14 | ' | ||
Nuclear decommissioning trust fund investments subtotal | 8,198 | [2] | 8,076 | [2] | ' |
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Net assets (liabilities) excluded from nuclear decommissioning trust fund investments | 17 | -5 | ' | ||
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 | 35 | 26 | ' | ||
Equity Securities [Abstract] | ' | ' | ' | ||
Equity securities | 5 | 16 | ' | ||
Equity securities subtotal | 5 | 16 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 40 | 49 | ' | ||
Debt securities issued by states of the United States and political subdivisions of the states | 18 | 20 | ' | ||
Corporate debt securities | 180 | 227 | ' | ||
Fixed income subtotal | 238 | 296 | ' | ||
Direct lending securities | 137 | 112 | ' | ||
Other debt obligations | ' | 1 | ' | ||
Pledged assets for Zion Station decommissioning subtotal | 415 | [3] | 451 | [3] | ' |
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Net assets (liabilities) excluded from nuclear decommissioning trust fund investments | 14 | 7 | ' | ||
Exelon Generation Co L L C [Member] | Rabbi Trust Investments [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 1 | 0 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Mutual funds | 13 | [7] | 13 | [7] | ' |
Rabbi trust investments subtotal | 14 | 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 | 10 | 10 | ' | ||
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 | 0 | ' | ||
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 | 4,641 | 3,960 | ' | ||
Proprietary trading | 1,341 | 1,761 | ' | ||
Effect of netting and allocation of collateral received/(paid) | -4,694 | [6] | -4,424 | [6] | ' |
Mark-to-market subtotal | 1,288 | 1,297 | ' | ||
Exelon Generation Co L L C [Member] | Commodity Mark To Market Derivative Liabilities [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Cash flow hedges | 0 | ' | ' | ||
Other derivatives | -4,295 | -2,827 | ' | ||
Proprietary trading | -1,318 | -1,703 | ' | ||
Effect of netting and allocation of collateral received/(paid) | 5,261 | [6] | 4,280 | [6] | ' |
Mark-to-market subtotal | -352 | -250 | ' | ||
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) | 22 | 32 | ' | ||
Interest rate mark to market | 51 | 62 | ' | ||
Interest rate mark-to-market Subtotal | 29 | 30 | ' | ||
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) | -28 | -32 | ' | ||
Interest rate mark to market | -45 | -44 | ' | ||
Interest rate mark-to-market Subtotal | -17 | -12 | ' | ||
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 | 329 | 1,006 | [1] | ' | |
Fixed income [Abstract] | ' | ' | ' | ||
Other investments | 13 | 0 | ' | ||
Deferred compensation | 0 | ' | ' | ||
Total assets | 3,655 | 4,266 | ' | ||
Total liabilities | 0 | 1 | ' | ||
Total net assets | 3,655 | 4,267 | ' | ||
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 | 117 | ' | 6 | ||
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 | 304 | 459 | ' | ||
Equity Securities [Abstract] | ' | ' | ' | ||
Equity securities | 1,813 | 1,776 | ' | ||
Exchange traded funds | 113 | 115 | ' | ||
Commingled funds | 0 | ' | ' | ||
Equity securities subtotal | 1,926 | ' | 1,891 | ||
Fixed income [Abstract] | ' | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 903 | 882 | ' | ||
Debt securities issued by states of the United States and political subdivisions of the states | 0 | ' | ' | ||
Fixed income subtotal | 903 | 882 | ' | ||
Other debt obligations | 0 | ' | ' | ||
Nuclear decommissioning trust fund investments subtotal | 3,133 | [2] | 3,232 | [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 | 16 | ' | ||
Equity securities subtotal | 4 | 16 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 36 | 45 | ' | ||
Fixed income subtotal | 36 | 45 | ' | ||
Pledged assets for Zion Station decommissioning subtotal | 40 | [3] | 61 | [3] | ' |
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member] | Rabbi Trust Investments [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 1 | 0 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Mutual funds | 13 | [7] | 13 | [7] | ' |
Rabbi trust investments subtotal | 14 | 13 | ' | ||
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 | 592 | 493 | ' | ||
Proprietary trading | 354 | 324 | ' | ||
Effect of netting and allocation of collateral received/(paid) | -826 | [6] | -863 | [6] | ' |
Mark-to-market subtotal | 120 | -46 | ' | ||
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 | -586 | -540 | ' | ||
Proprietary trading | -357 | -328 | ' | ||
Effect of netting and allocation of collateral received/(paid) | 943 | [6] | 869 | [6] | ' |
Mark-to-market subtotal | 0 | 1 | ' | ||
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) | 18 | 30 | ' | ||
Interest rate mark to market | 24 | 30 | ' | ||
Interest rate mark-to-market Subtotal | 6 | ' | ' | ||
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) | -25 | -31 | ' | ||
Interest rate mark to market | -25 | -31 | ' | ||
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 | -29 | -29 | ' | ||
Total assets | 5,469 | 5,568 | ' | ||
Total liabilities | -146 | -180 | ' | ||
Total net assets | 5,323 | 5,388 | ' | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Deferred compensation | 29 | 29 | ' | ||
Collateral received from counterparties, net of collateral paid to counterparties | 332 | ' | -124 | ||
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 | 2,053 | 2,271 | ' | ||
Equity securities subtotal | 2,053 | 2,271 | ' | ||
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 | 294 | ' | ||
Debt securities issued by foreign governments | 87 | 87 | ' | ||
Corporate debt securities | 1,795 | 1,753 | ' | ||
Federal agency mortgage-backed securities | 9 | 10 | ' | ||
Commercial mortgage-backed securities (non-agency) | 40 | 40 | ' | ||
Residential mortgage-backed securities (non-agency) | 7 | 7 | ' | ||
Mutual funds fixed income | 278 | 18 | ' | ||
Fixed income subtotal | 2,511 | 2,209 | ' | ||
Other debt obligations | 15 | 14 | ' | ||
Nuclear decommissioning trust fund investments subtotal | 4,579 | [2] | 4,494 | [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 | 35 | 26 | ' | ||
Equity Securities [Abstract] | ' | ' | ' | ||
Equity securities | 1 | ' | ' | ||
Equity securities subtotal | 1 | 0 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 4 | 4 | ' | ||
Debt securities issued by states of the United States and political subdivisions of the states | 18 | 20 | ' | ||
Corporate debt securities | 180 | 227 | ' | ||
Fixed income subtotal | 202 | 251 | ' | ||
Direct lending securities | 0 | ' | ' | ||
Other debt obligations | ' | 1 | ' | ||
Pledged assets for Zion Station decommissioning subtotal | 238 | [3] | 278 | [3] | ' |
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 | 2,778 | 2,582 | ' | ||
Proprietary trading | 808 | 1,315 | ' | ||
Effect of netting and allocation of collateral received/(paid) | -2,957 | [6] | -3,131 | [6] | ' |
Mark-to-market subtotal | 629 | 766 | ' | ||
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 | -2,624 | -1,890 | ' | ||
Proprietary trading | -765 | -1,256 | ' | ||
Effect of netting and allocation of collateral received/(paid) | 3,289 | [6] | 3,007 | [6] | ' |
Mark-to-market subtotal | -100 | -139 | ' | ||
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) | 4 | 2 | ' | ||
Interest rate mark to market | 27 | 32 | ' | ||
Interest rate mark-to-market Subtotal | 23 | 30 | ' | ||
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 2 [Member] | Interest Rate Mark To Market Derivative Liabilities [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Effect of netting and allocation of collateral received/(paid) | -3 | -1 | ' | ||
Interest rate mark to market | -20 | -13 | ' | ||
Interest rate mark-to-market Subtotal | -17 | -12 | ' | ||
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 | 10 | 15 | ' | ||
Deferred compensation | 0 | ' | ' | ||
Total assets | 1,172 | 1,054 | ' | ||
Total liabilities | -252 | -112 | ' | ||
Total net assets | 920 | 942 | ' | ||
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 | 118 | ' | -26 | ||
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 | ' | ' | ||
Corporate debt securities | 126 | 31 | ' | ||
Mutual funds fixed income | 0 | ' | ' | ||
Fixed income subtotal | 126 | 31 | ' | ||
Private equity | 4 | 5 | ' | ||
Direct lending securities | 356 | 314 | ' | ||
Other debt obligations | 0 | ' | ' | ||
Nuclear decommissioning trust fund investments subtotal | 486 | [2] | 350 | [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 | 137 | 112 | ' | ||
Pledged assets for Zion Station decommissioning subtotal | 137 | [3] | 112 | [3] | ' |
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 | 1,271 | 885 | ' | ||
Proprietary trading | 179 | 122 | ' | ||
Effect of netting and allocation of collateral received/(paid) | -911 | [6] | -430 | [6] | ' |
Mark-to-market subtotal | 539 | 577 | ' | ||
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 | -1,085 | -397 | ' | ||
Proprietary trading | -196 | -119 | ' | ||
Effect of netting and allocation of collateral received/(paid) | 1,029 | [6] | 404 | [6] | ' |
Mark-to-market subtotal | -252 | -112 | ' | ||
Commonwealth Edison Co [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Deferred compensation | -8 | -8 | ' | ||
Total assets | 2 | 5 | ' | ||
Total liabilities | -176 | -201 | ' | ||
Total net assets | -174 | -196 | ' | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Deferred compensation | 8 | 8 | ' | ||
Mark-to-market derivative liabilities (current liabilities) | 13 | 17 | ' | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | 155 | 176 | ' | ||
Commonwealth Edison Co [Member] | Rabbi Trust Investments [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Mutual funds | 2 | 5 | ' | ||
Rabbi trust investments subtotal | 2 | 5 | ' | ||
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 | 0 | ' | ||
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 | 13 | 17 | ' | ||
Fair value of energy swap contract noncurrent liability | 155 | 176 | ' | ||
Commonwealth Edison Co [Member] | Commodity Mark To Market Derivative Liabilities [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Mark-to-market subtotal | 168 | [8] | 193 | [8] | ' |
Commonwealth Edison Co [Member] | Fair Value Inputs Level 1 [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Deferred compensation | 0 | ' | ' | ||
Total assets | 2 | 5 | ' | ||
Total liabilities | 0 | 0 | ' | ||
Total net assets | 2 | 5 | ' | ||
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 | 2 | 5 | ' | ||
Rabbi trust investments subtotal | 2 | 5 | ' | ||
Commonwealth Edison Co [Member] | Fair Value Inputs Level 1 [Member] | Derivative Financial Instruments Liabilities [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Mark-to-market subtotal | 0 | [8] | ' | ' | |
Commonwealth Edison Co [Member] | Fair Value Inputs Level 2 [Member] | ' | ' | ' | ||
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 | [8] | ' | ' | |
Commonwealth Edison Co [Member] | Fair Value Inputs Level 3 [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Deferred compensation | 0 | ' | ' | ||
Total assets | 0 | 0 | ' | ||
Total liabilities | -168 | -193 | ' | ||
Total net assets | -168 | -193 | ' | ||
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 | 168 | [8] | 193 | [8] | ' |
PECO Energy Co [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 32 | 175 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Deferred compensation | -17 | -17 | ' | ||
Total assets | 41 | 184 | ' | ||
Total liabilities | -17 | -17 | ' | ||
Total net assets | 24 | 167 | ' | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Deferred compensation | 17 | 17 | ' | ||
PECO Energy Co [Member] | Rabbi Trust Investments [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Mutual funds | 9 | 9 | ' | ||
Rabbi trust investments subtotal | 9 | [10],[9] | 9 | [10],[9] | ' |
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 | 14 | ' | ||
PECO Energy Co [Member] | Fair Value Inputs Level 1 [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 32 | 175 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Total assets | 41 | 184 | ' | ||
Total net assets | 41 | 184 | ' | ||
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 | [10],[9] | 9 | [10],[9] | ' |
PECO Energy Co [Member] | Fair Value Inputs Level 2 [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Deferred compensation | -17 | -17 | ' | ||
Total liabilities | -17 | -17 | ' | ||
Total net assets | -17 | -17 | ' | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Deferred compensation | 17 | 17 | ' | ||
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] | Rabbi Trust Investments [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Mutual funds | 4 | [9] | 6 | [9] | ' |
Baltimore Gas and Electric Company [Member] | Derivative Financial Instruments Assets [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 30 | 31 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Total assets | 34 | 37 | ' | ||
Total net assets | 30 | 31 | ' | ||
Baltimore Gas and Electric Company [Member] | Derivative Financial Instruments Liabilities [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Deferred compensation | -4 | -6 | ' | ||
Total liabilities | -4 | -6 | ' | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Deferred compensation | 4 | 6 | ' | ||
Baltimore Gas and Electric Company [Member] | Fair Value Inputs Level 1 [Member] | Rabbi Trust Investments [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Mutual funds | 4 | [9] | 6 | [9] | ' |
Baltimore Gas and Electric Company [Member] | Fair Value Inputs Level 1 [Member] | Derivative Financial Instruments Assets [Member] | ' | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Cash equivalents | 30 | 31 | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Total assets | 34 | 37 | ' | ||
Total net assets | 34 | 37 | ' | ||
Baltimore Gas and Electric Company [Member] | Fair Value Inputs Level 2 [Member] | Derivative Financial Instruments Assets [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Total net assets | -4 | -6 | ' | ||
Baltimore Gas and Electric Company [Member] | Fair Value Inputs Level 2 [Member] | Derivative Financial Instruments Liabilities [Member] | ' | ' | ' | ||
Fixed income [Abstract] | ' | ' | ' | ||
Deferred compensation | -4 | -6 | ' | ||
Total liabilities | -4 | -6 | ' | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ' | ||
Deferred compensation | $4 | $6 | ' | ||
[1] | Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value. | ||||
[2] | Excludes net assets (liabilities) of $17 million and $(5) million at March 31, 2014 and December 31, 2013, 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 $14 million and $7 million at March 31, 2014 and December 31, 2013, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases. | ||||
[4] | The mutual funds held by the Rabbi trusts include $41 million related to deferred compensation and $1 million related to Supplemental Executive Retirement Plan at March 31, 2014, and $53 million related to deferred compensation and $1 million related to Supplemental Executive Retirement Plan at December 31, 2013. | ||||
[5] | Excludes $33 million and $32 million of the cash surrender value of life insurance investments at March 31, 2014 and December 31, 2013, respectively. | ||||
[6] | Includes collateral postings (received) from counterparties. Collateral posted (received) from counterparties, net of collateral paid to counterparties, totaled $117 million, $332 million and $118 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of March 31, 2014. Collateral posted (received) from counterparties, net of collateral paid to counterparties, totaled $6 million, $(124) million and $(26) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2013. | ||||
[7] | Excludes $10 million of the cash surrender value of life insurance investments at both March 31, 2014 and December 31, 2013. | ||||
[8] | The Level 3 balance includes the current and noncurrent liability of $13 million and $155 million at March 31, 2014, respectively, and $17 million and $176 million at December 31, 2013, respectively, related to floating-to-fixed energy swap contracts with unaffiliated suppliers. | ||||
[9] | Excludes $14 million of the cash surrender value of life insurance investments at both March 31, 2014 and December 31, 2013. | ||||
[10] | 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 | |||
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 | ||
Fair Value Inputs Level 3 [Member] | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract] | ' | ' | ||
Beginning balance | $749 | $656 | ||
Total realized / unrealized gains (losses) | ' | ' | ||
Included in income | 311 | 126 | ||
Included in other comprehensive income | ' | 0 | ||
Included in payable for Zion Station decommissioning | -1 | ' | ||
Included in regulatory assets | -28 | 7 | ||
Change in collateral | 144 | 33 | ||
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract] | ' | ' | ||
Purchases | 181 | 49 | ||
Sales | -7 | 26 | ||
Settlements | -6 | ' | ||
Transfers into Level 3 - (Asset) / Liability | -26 | ' | ||
Transfers out of Level 3 - (Asset) / Liability | 1 | 4 | ||
Ending balance | 752 | 583 | ||
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities | -446 | -78 | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract] | ' | ' | ||
Fair value of Constellation fair value assets acquired | ' | 10 | ||
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 | 350 | 183 | ||
Total realized / unrealized gains (losses) | ' | ' | ||
Included in income | -1 | -1 | ||
Included in regulatory assets | -3 | -1 | ||
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract] | ' | ' | ||
Purchases | 139 | 32 | ||
Sales | -1 | 7 | ||
Settlements | -6 | ' | ||
Ending balance | 486 | 210 | ||
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 | 112 | 89 | ||
Total realized / unrealized gains (losses) | ' | ' | ||
Included in payable for Zion Station decommissioning | -1 | ' | ||
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract] | ' | ' | ||
Purchases | 30 | 22 | ||
Sales | -4 | 7 | ||
Ending balance | 137 | 104 | ||
Derivative [Member] | Fair Value Inputs Level 3 [Member] | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract] | ' | ' | ||
Beginning balance | 272 | 367 | ||
Total realized / unrealized gains (losses) | ' | ' | ||
Included in income | 312 | [1],[2] | 127 | [3] |
Included in other comprehensive income | ' | 0 | [4] | |
Included in regulatory assets | -25 | [5] | 8 | [6] |
Change in collateral | 144 | 33 | ||
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract] | ' | ' | ||
Purchases | 10 | -5 | [7] | |
Sales | -2 | 4 | ||
Transfers into Level 3 - (Asset) / Liability | -26 | ' | ||
Transfers out of Level 3 - (Asset) / Liability | 8 | 4 | ||
Ending balance | 119 | 260 | ||
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities | -446 | -79 | ||
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 | -58 | 58 | ||
Increase (decrease) in fair value related to the swap contract | ' | 8 | ||
Realized gains (losses) related to swap contract | ' | 133 | ||
Other Investments [Member] | Fair Value Inputs Level 3 [Member] | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract] | ' | ' | ||
Beginning balance | 15 | 17 | ||
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract] | ' | ' | ||
Purchases | 2 | 0 | ||
Sales | 0 | 8 | ||
Transfers out of Level 3 - (Asset) / Liability | -7 | ' | ||
Ending balance | 10 | 9 | ||
Exelon Generation Co L L C [Member] | ' | ' | ||
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 | -134 | ' | ||
Increase (decrease) in fair value related to the swap contract | 0 | ' | ||
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 | 942 | 949 | ||
Total realized / unrealized gains (losses) | ' | ' | ||
Included in income | 311 | 143 | ||
Included in other comprehensive income | 0 | 124 | ||
Included in payable for Zion Station decommissioning | -1 | ' | ||
Included in regulatory assets | -3 | ' | ||
Included in noncurrent payables to affiliates | ' | 1 | ||
Change in collateral | 144 | 33 | ||
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract] | ' | ' | ||
Purchases | 181 | [8] | 49 | |
Sales | -7 | -26 | ||
Settlements | -6 | ' | ||
Transfers into Level 3 - (Asset) / Liability | -26 | ' | ||
Transfers out of Level 3 - (Asset) / Liability | 1 | 4 | ||
Ending balance | 920 | 743 | ||
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities | -446 | -85 | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract] | ' | ' | ||
Fair value of Constellation fair value assets acquired | ' | 323 | ||
Acquisition of marketable securities | ' | 17 | ||
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 | 350 | 183 | ||
Total realized / unrealized gains (losses) | ' | ' | ||
Included in income | -1 | -1 | ||
Included in regulatory assets | -3 | ' | ||
Included in noncurrent payables to affiliates | ' | 1 | ||
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract] | ' | ' | ||
Purchases | 139 | [8] | 32 | |
Sales | -1 | -7 | ||
Settlements | -6 | ' | ||
Ending balance | 486 | 210 | ||
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 | 112 | 89 | ||
Total realized / unrealized gains (losses) | ' | ' | ||
Included in payable for Zion Station decommissioning | -1 | ' | ||
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract] | ' | ' | ||
Purchases | 30 | [8] | 22 | |
Sales | -4 | -7 | ||
Ending balance | 137 | 104 | ||
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 | 465 | 660 | ||
Total realized / unrealized gains (losses) | ' | ' | ||
Included in income | 312 | [9] | 144 | [10],[11],[3] |
Included in other comprehensive income | 0 | [8] | 124 | [12],[6] |
Included in regulatory assets | 0 | ' | ||
Change in collateral | 144 | 33 | ||
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract] | ' | ' | ||
Purchases | 10 | -5 | [7] | |
Sales | -2 | -4 | ||
Transfers into Level 3 - (Asset) / Liability | -26 | ' | ||
Transfers out of Level 3 - (Asset) / Liability | 8 | 4 | ||
Ending balance | 287 | 420 | ||
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities | -446 | -86 | ||
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 | ' | -58 | ||
Increase (decrease) in fair value related to the swap contract | ' | 8 | ||
Realized gains (losses) related to swap contract | ' | -147 | ||
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 | 15 | 17 | ||
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract] | ' | ' | ||
Purchases | 2 | 0 | ||
Sales | 0 | -8 | ||
Transfers into Level 3 - (Asset) / Liability | -10 | ' | ||
Transfers out of Level 3 - (Asset) / Liability | -7 | ' | ||
Ending balance | ' | 9 | ||
Commonwealth Edison Co [Member] | Derivative [Member] | Fair Value Inputs Level 3 [Member] | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract] | ' | ' | ||
Beginning balance | -193 | -293 | ||
Total realized / unrealized gains (losses) | ' | ' | ||
Included in regulatory assets | -25 | [13],[14] | -133 | |
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract] | ' | ' | ||
Ending balance | -168 | -160 | ||
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 | -135 | ||
Realized gains (losses) related to swap contract | 0 | 133 | ||
Realized gains (losses) related to swap contract with unaffiliated parties | -5 | ' | ||
Increase (decrease) in fair value related to floating-to-fixed energy swap contracts | ($30) | $11 | ||
[1] | ) Includes an increase for the reclassification of $134 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three months ended March 31, 2014. | |||
[2] | Includes the reclassification of $##D<grclrelloss> million and $##D<gpyrclrellossq2q3> million of realized losses due to the settlement of derivative contracts recorded in results of operations for the ##D<threemonth> and ##D<curmonth> months ended ##D<cyperiod>. | |||
[3] | Includes the reclassification of $##D<eqtdreclasssettlementpy> million and $##D<eytdreclasssettlementpy> million of realized losses due to the settlement of derivative contracts recorded in results of operations for the ##D<threemonth> and ##D<curmonth> months ended ##D<pyperiod>, respectively. | |||
[4] | b)B B B B B B B B Excludes increases in fair value of $8 million and realized losses reclassified due to settlements of $133 million associated with Generationbs financial swap contract with ComEd for the three months ended March 31, 2013. | |||
[5] | Excludes decreases in fair value of $##D<gcomedfvpretaxqtdq2q3> million and $##D<gcomedfvpretaxytd> million and realized losses reclassified due to settlements of $##D<gcomedreclassqtdq2q3> million and $##D<gcomedreclassytd> million associated with Generation?s financial swap contract with ComEd for the ##D<threemonth> and ##D<curmonth> months ended ##D<cyperiod>. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements. | |||
[6] | Excludes $##D<gcomedfvpretaxqtdq2q3py> million and $##D<gcomedfvpretaxytdpy> million of decreases in fair value and $##D<gcomedreclassqtdq2q3py> million and $##D<gcomedreclassytdpy> million of realized losses due to settlements for the ##D<threemonth> and ##D<curmonth> months ended ##D<pyperiod> of Generation?s financial swap contract with ComEd, which eliminates upon consolidation in Exelon?s Consolidated Financial Statements. | |||
[7] | Includes $##D<gpyfvacquiredq2q3> million of fair value from contracts and $##D<gpyfvothinvestq2q3> million of other investments acquired as a result of the merger. | |||
[8] | ||||
[9] | (a)B B B B B B B B Includes an increase for the reclassification of $134 million of realized losses due to the settlement of derivative contracts recorded in results of operations. | |||
[10] | (a)B B B B B B B B Includes the reclassification of $58 million of realized losses due to the settlement of derivative contracts recorded in results of operations. | |||
[11] | ) Includes the reclassification of $##D<gqtdreclasssettlementpy> million and $##D<gytdreclasssettlementpy> million of realized losses due to the settlement of derivative contracts recorded in results of operations for the ##D<threemonth> and ##D<curmonth> months ended ##D<pyperiod>, respectively. | |||
[12] | (b)B B B B B B B B Includes $8 million of increases in fair value and $133 million of realized losses due to settlements during 2013 of Generation's financial swap contract with ComEd, which eliminates upon consolidation in Exelon's Consolidated Financial Statements. | |||
[13] | (a)B B B B B B B B | |||
[14] | Includes $30 million of decrease in the fair value partially offset by realized gains due to settlements of $5 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended March 31, 2014. |
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 | |
Mar. 31, 2014 | Mar. 31, 2013 | |
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 | ($268,000,000) | ($159,000,000) |
Change in the unrealized gains (losses) relating to assets and liabilities held | -425,000,000 | -117,000,000 |
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 | -44,000,000 | 32,000,000 |
Change in the unrealized gains (losses) relating to assets and liabilities held | -21,000,000 | 38,000,000 |
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 | 1,000,000 | 1,000,000 |
Change in the unrealized gains (losses) relating to assets and liabilities held | ' | 1,000,000 |
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 | -268,000,000 | -176,000,000 |
Change in the unrealized gains (losses) relating to assets and liabilities held | -425,000,000 | -124,000,000 |
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 | -44,000,000 | 32,000,000 |
Change in the unrealized gains (losses) relating to assets and liabilities held | -21,000,000 | 38,000,000 |
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 | 1,000,000 | 814,139.21 |
Change in the unrealized gains (losses) relating to assets and liabilities held | ' | $1,065,685.19 |
Fair_Value_of_Financial_Assets7
Fair Value of Financial Assets and Liabilities (Fair Value Inputs Assets Quantitative Information) (Details) (USD $) | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2014 | Dec. 31, 2013 | |||
Derivatives Fair Value [Line Items] | ' | ' | ||
Forward Power Basis | 3.83 | ' | ||
Forward Gas Basis | 0.37 | ' | ||
Derivatives Fair Value Footnotes [Abstract] | ' | ' | ||
Cash collateral excluded | 118,000,000 | ' | ||
Fair Value Inputs Level 3 [Member] | ' | ' | ||
Derivatives Fair Value Footnotes [Abstract] | ' | ' | ||
Cash collateral excluded | ' | 26,000,000 | ||
Exelon Generation Co L L C [Member] | ' | ' | ||
Derivatives Fair Value Footnotes [Abstract] | ' | ' | ||
Outstanding Commitments to invest | 469,000,000 | ' | ||
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 | 186,000,000 | [1] | 488,000,000 | [2] |
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 | 19,000,000 | 8,000,000 | [3] | |
Forward gas price assets | 2.18 | 2.98 | [3] | |
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 | 155,000,000 | 176,000,000 | [3] | |
Forward gas price assets | 17.65 | 16.63 | [3] | |
Renewable factor | ' | 128.00% | ||
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 | 14.00% | 15.00% | [3] | |
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 | 207.00% | 142.00% | [3] | |
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 | ' | -3,000,000 | [2] | |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | 17,000,000 | [1] | ' | |
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 | -26,000,000 | -10,000,000 | [3] | |
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 | -152,000,000 | -176,000,000 | [3] | |
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 | 12.00% | 14.00% | [3] | |
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 | 59.00% | 19.00% | [3] | |
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 | 168,000,000 | [1] | ' | |
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 | ' | 193,000,000 | [2] | |
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% | [4] | |
Renewable factor | 87.00% | 84.00% | ||
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% | 8.00% | ||
Forward heat rate | -9.00% | -9.00% | [4] | |
Renewable factor | 127.00% | ' | ||
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 $118 million as of March 31, 2014. The upper ends of the ranges are driven by the winter power and gas prices in the New England region. Without the New England region, the upper ends of the ranges for power and gas would be approximately $114 and $10.62, respectively. | |||
[2] | The fair values do not include cash collateral held on level three positions of $26 million as of December 31, 2013 The upper ends of the ranges are driven by the winter power and gas prices in the New England region. Without the New England region, the upper ends of the ranges for power and gas would be approximately $100 and $5.70, respectively. | |||
[3] | 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. | |||
[4] | 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 | |
Mar. 31, 2014 | Mar. 31, 2013 | |
GWh | GWh | |
Exelon Generation Co L L C [Member] | ' | ' |
Proprietary Trading Volumes [Abstract] | ' | ' |
Proprietary trading activities volume | 2,494 | 1,572 |
Exelon Generation Co L L C [Member] | Minimum [Member] | ' | ' |
Percent Of Expected Generation Being Hedged [Abstract] | ' | ' |
Expected generation hedged in next twelve months | 91.00% | ' |
Expected generation hedged in year two | 64.00% | ' |
Expected generation hedged in year three | 37.00% | ' |
Exelon Generation Co L L C [Member] | Maximum [Member] | ' | ' |
Percent Of Expected Generation Being Hedged [Abstract] | ' | ' |
Expected generation hedged in next twelve months | 94.00% | ' |
Expected generation hedged in year two | 67.00% | ' |
Expected generation hedged in year three | 40.00% | ' |
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 $) | 3 Months Ended | 12 Months Ended | ||||
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | |||
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 | $2 | ' | ' | |||
Derivative Interest Rate Risk [Abstract] | ' | ' | ' | |||
Mark-to-market derivative assets (current assets) | 2 | ' | -1 | |||
Mark-to-market derivative assets (noncurrent assets) | 37 | ' | 38 | |||
Total mark-to-market derivative assets | 39 | ' | 37 | |||
Mark-to-market derivative liabilities (current liabilities) | -2 | ' | -1 | |||
Mark-to-market derivative liabilities (noncurrent liabilities) | -16 | ' | -15 | |||
Total mark-to-market derivative liabilities | -18 | ' | -16 | |||
Total mark-to-market derivative net assets (liabilities) | 21 | ' | 21 | |||
Derivative, Gain (Loss) on Derivative, Net [Abstract] | ' | ' | ' | |||
Gain on swaps/borrowings | 4 | 1 | ' | |||
Loss on swaps/borrowings | ' | -6 | ' | |||
Interest Rate Risk - Fair Value Hedges [Abstract] | ' | ' | ' | |||
Notional amount of interest rate swaps acquired from merger | 150 | ' | ' | |||
Fair value of interest rate swaps acquired from merger | 2 | ' | ' | |||
Interest Rate Risk - Cash Flow Hedges [Abstract] | ' | ' | ' | |||
Mark-to-market derivative liabilities | 287 | ' | 300 | |||
Unrealized Gain (Loss) on Derivatives | -730 | -388 | ' | |||
Designated as Hedging Instrument [Member] | ' | ' | ' | |||
Interest Rate Risk - Cash Flow Hedges [Abstract] | ' | ' | ' | |||
Notional Amount of Pre-issuance Interest Rate Cash Flow Hedge Derivatives | 530 | ' | ' | |||
Designated as Hedging Instrument [Member] | Interest Rate Cash Flow Hedge Derivatives | Cash Flow Hedging [Member] | ' | ' | ' | |||
Interest Rate Risk - Cash Flow Hedges [Abstract] | ' | ' | ' | |||
Notional Amount of Pre-issuance Interest Rate Cash Flow Hedge Derivatives | 100 | ' | ' | |||
Designated as Hedging Instrument [Member] | Interest Rate Swap | Fair Value Hedging [Member] | ' | ' | ' | |||
Derivative, Gain (Loss) on Derivative, Net [Abstract] | ' | ' | ' | |||
Gain on swaps/borrowings | 2 | ' | ' | |||
Interest Rate Risk - Fair Value Hedges [Abstract] | ' | ' | ' | |||
Increase (Decrease) in Fair Value of Interest Rate Fair Value Hedging Instruments | 28 | ' | 26 | |||
Interest Rate Risk - Cash Flow Hedges [Abstract] | ' | ' | ' | |||
Derivative, Notional Amount | 1,400 | ' | 1,275 | |||
Increase In Notional Amount Of Derivative Instruments | 50 | ' | ' | |||
Increase In Notional Amount Of Derivative Instruments1 | 75 | ' | ' | |||
Derivative [Member] | ' | ' | ' | |||
Derivative Interest Rate Risk [Abstract] | ' | ' | ' | |||
Mark-to-market derivative assets (noncurrent assets) | 23 | ' | ' | |||
Derivative [Member] | Interest Rate Swap | ' | ' | ' | |||
Interest Rate Risk - Cash Flow Hedges [Abstract] | ' | ' | ' | |||
Derivative, Notional Amount | 1,550 | ' | ' | |||
Exelon Generation Co L L C [Member] | ' | ' | ' | |||
Derivative Interest Rate Risk [Abstract] | ' | ' | ' | |||
Mark-to-market derivative assets (current assets) | 2 | ' | -1 | |||
Mark-to-market derivative assets (noncurrent assets) | 27 | ' | 31 | |||
Total mark-to-market derivative assets | 29 | ' | 30 | |||
Mark-to-market derivative liabilities (current liabilities) | -2 | ' | -1 | |||
Mark-to-market derivative liabilities (noncurrent liabilities) | -15 | ' | -11 | |||
Total mark-to-market derivative liabilities | -17 | ' | -12 | |||
Total mark-to-market derivative net assets (liabilities) | 12 | ' | 18 | |||
Derivative, Gain (Loss) on Derivative, Net [Abstract] | ' | ' | ' | |||
Loss on swaps/borrowings | -1 | [1] | -1 | [1] | ' | |
Interest Rate Risk - Cash Flow Hedges [Abstract] | ' | ' | ' | |||
Percentage of interest rate swap in relation to DOE guarantee | 75 | ' | ' | |||
Notional amount of interest rate swap DOE advance | 350 | ' | ' | |||
Percent of DOE loan advance offset | 75.00% | ' | ' | |||
Notional amount of remaining cash flow hedges | 135 | ' | ' | |||
Mark-to-market derivative liabilities | 131 | ' | 120 | |||
Unrealized Gain (Loss) on Derivatives | -737 | -406 | ' | |||
Exelon Generation Co L L C [Member] | Antelope Valle [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | ' | ' | ' | |||
Interest Rate Risk - Cash Flow Hedges [Abstract] | ' | ' | ' | |||
DOE interest rate swap | 485 | ' | ' | |||
Exelon Generation Co L L C [Member] | Other Solar Projects [Member] | ' | ' | ' | |||
Interest Rate Risk - Cash Flow Hedges [Abstract] | ' | ' | ' | |||
Notional amounts on forward starting interest rate swaps | 28 | ' | ' | |||
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | ' | ' | ' | |||
Derivative Interest Rate Risk [Abstract] | ' | ' | ' | |||
Mark-to-market derivative assets (noncurrent assets) | 20 | ' | 26 | |||
Total mark-to-market derivative assets | 20 | ' | 26 | |||
Mark-to-market derivative liabilities (current liabilities) | -1 | ' | -1 | |||
Mark-to-market derivative liabilities (noncurrent liabilities) | -15 | ' | -10 | |||
Total mark-to-market derivative liabilities | -16 | ' | -11 | |||
Total mark-to-market derivative net assets (liabilities) | 4 | ' | 15 | |||
Interest Rate Risk - Cash Flow Hedges [Abstract] | ' | ' | ' | |||
Notional Amount of Pre-issuance Interest Rate Cash Flow Hedge Derivatives | 430 | ' | ' | |||
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Interest Rate Cash Flow Hedge Derivatives | Cash Flow Hedging [Member] | ' | ' | ' | |||
Interest Rate Risk - Cash Flow Hedges [Abstract] | ' | ' | ' | |||
Increase In Notional Amount Of Derivative Instruments | 240 | ' | ' | |||
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Foreign Currency Fair Value Hedge Derivatives | ' | ' | ' | |||
Interest Rate Risk - Cash Flow Hedges [Abstract] | ' | ' | ' | |||
Derivative, Notional Amount | 164 | ' | ' | |||
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Interest Rate Swap | ' | ' | ' | |||
Interest Rate Risk - Cash Flow Hedges [Abstract] | ' | ' | ' | |||
Derivative, Notional Amount | 195 | ' | ' | |||
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Interest Rate Swap | Fair Value Hedging [Member] | ' | ' | ' | |||
Derivative, Gain (Loss) on Derivative, Net [Abstract] | ' | ' | ' | |||
Loss on swaps/borrowings | -5 | [1] | -4 | [1] | ' | |
Interest Rate Risk - Fair Value Hedges [Abstract] | ' | ' | ' | |||
Increase (Decrease) in Fair Value of Interest Rate Fair Value Hedging Instruments | 19 | ' | 23 | |||
Interest rate swaps previously held by acquiree | 550 | ' | 550 | |||
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Other Solar Projects [Member] | ' | ' | ' | |||
Interest Rate Risk - Cash Flow Hedges [Abstract] | ' | ' | ' | |||
Notional amounts on forward starting interest rate swaps | 27 | ' | ' | |||
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Other Solar Projects [Member] | Interest Rate Cash Flow Hedge Derivatives | Cash Flow Hedging [Member] | ' | ' | ' | |||
Derivative Interest Rate Risk [Abstract] | ' | ' | ' | |||
Mark-to-market derivative assets (noncurrent assets) | 2 | ' | ' | |||
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Interest Expense [Member] | Interest Rate Swap | Fair Value Hedging [Member] | ' | ' | ' | |||
Derivative Instruments Gain Loss Recognized In Income Net Footnotes [Abstract] | ' | ' | ' | |||
GainLossOnFairValueHedgesRecognizedInEarnings | -4 | -4 | ' | |||
Exelon Generation Co L L C [Member] | Derivative [Member] | ' | ' | ' | |||
Derivative Interest Rate Risk [Abstract] | ' | ' | ' | |||
Mark-to-market derivative assets (current assets) | 4 | ' | 3 | |||
Mark-to-market derivative assets (noncurrent assets) | 2 | ' | 3 | |||
Total mark-to-market derivative assets | 6 | ' | 6 | |||
Mark-to-market derivative liabilities (current liabilities) | -3 | ' | -1 | |||
Mark-to-market derivative liabilities (noncurrent liabilities) | -1 | ' | -1 | |||
Total mark-to-market derivative liabilities | -4 | ' | -2 | |||
Total mark-to-market derivative net assets (liabilities) | 2 | ' | 4 | |||
Exelon Generation Co L L C [Member] | Derivative [Member] | Interest Rate Swap | ' | ' | ' | |||
Interest Rate Risk - Cash Flow Hedges [Abstract] | ' | ' | ' | |||
Derivative, Notional Amount | 700 | ' | ' | |||
Exelon Generation Co L L C [Member] | Derivative [Member] | Other Solar Projects [Member] | ' | ' | ' | |||
Interest Rate Risk - Cash Flow Hedges [Abstract] | ' | ' | ' | |||
Mark-to-market derivative liabilities | 2 | ' | ' | |||
Exelon Generation Co L L C [Member] | Derivative [Member] | Interest Expense [Member] | Antelope Valle [Member] | ' | ' | ' | |||
Interest Rate Risk - Cash Flow Hedges [Abstract] | ' | ' | ' | |||
Mark-to-market derivative liabilities | 14 | ' | ' | |||
Exelon Generation Co L L C [Member] | Proprietary Trading [Member] | ' | ' | ' | |||
Derivative Interest Rate Risk [Abstract] | ' | ' | ' | |||
Mark-to-market derivative assets (current assets) | 12 | [2] | ' | 15 | [2] | |
Mark-to-market derivative assets (noncurrent assets) | 13 | [2] | ' | 15 | [2] | |
Total mark-to-market derivative assets | 25 | [2] | ' | 30 | [2] | |
Mark-to-market derivative liabilities (current liabilities) | -15 | [2] | ' | -18 | [2] | |
Mark-to-market derivative liabilities (noncurrent liabilities) | -10 | [2] | ' | -13 | [2] | |
Total mark-to-market derivative liabilities | -25 | [2] | ' | -31 | [2] | |
Total mark-to-market derivative net assets (liabilities) | 0 | [2] | ' | -1 | [2] | |
Exelon Generation Co L L C [Member] | Collateral And Netting [Member] | ' | ' | ' | |||
Derivative Interest Rate Risk [Abstract] | ' | ' | ' | |||
Mark-to-market derivative assets (current assets) | -14 | [3] | ' | 19 | [3] | |
Mark-to-market derivative assets (noncurrent assets) | -8 | [3] | ' | 13 | [3] | |
Total mark-to-market derivative assets | -22 | [3] | ' | 32 | [3] | |
Mark-to-market derivative liabilities (current liabilities) | 17 | [3] | ' | -19 | [3] | |
Mark-to-market derivative liabilities (noncurrent liabilities) | 11 | [3] | ' | -13 | [3] | |
Total mark-to-market derivative liabilities | 28 | [3] | ' | -32 | [3] | |
Total mark-to-market derivative net assets (liabilities) | 6 | [3] | ' | ' | ||
Other Segments [Member] | Designated as Hedging Instrument [Member] | ' | ' | ' | |||
Derivative Interest Rate Risk [Abstract] | ' | ' | ' | |||
Mark-to-market derivative assets (noncurrent assets) | 10 | ' | 7 | |||
Total mark-to-market derivative assets | 10 | ' | 7 | |||
Mark-to-market derivative liabilities (noncurrent liabilities) | -1 | ' | -4 | |||
Total mark-to-market derivative liabilities | -1 | ' | -4 | |||
Total mark-to-market derivative net assets (liabilities) | $9 | ' | $3 | |||
[1] | For the three months ended March 31, 2014 and 2013, the loss on Generation swaps included $4 million and $4 million realized in earnings, respectively, with an immaterial amount excluded from hedge effectiveness testing | |||||
[2] | 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 proprietary trading interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates. | |||||
[3] | 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 | 12 Months Ended | ||||||
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | ||||
Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract] | ' | ' | ' | ' | ||||
Ineffective portion recognized in income | $5 | ' | ' | ' | ||||
Derivatives Fair Value [Line Items] | ' | ' | ' | ' | ||||
Mark-to-market derivative assets | 756 | ' | 727 | ' | ||||
Mark-to-market derivative assets (noncurrent assets) | 571 | ' | 607 | ' | ||||
Mark-to-market derivative liabilities (current liabilities) | -251 | ' | -159 | ' | ||||
Mark-to-market derivative liabilities (noncurrent liabilities) | -287 | ' | -300 | ' | ||||
Other Derivatives Not Designated As Hedging Instruments [Abstract] | ' | ' | ' | ' | ||||
Change in fair value | -682 | -329 | ' | ' | ||||
Reclassification to realized at settlement | -48 | -57 | ' | ' | ||||
Net mark-to-market gains (losses) | -730 | -386 | ' | ' | ||||
Operating Revenue [Member] | ' | ' | ' | ' | ||||
Proprietary Trading Activities [Abstract] | ' | ' | ' | ' | ||||
Change in fair value | -3 | -4 | ' | ' | ||||
Reclassification to realized at settlement | 1 | 6 | ' | ' | ||||
Net mark-to-market gains (losses) | -2 | 2 | ' | ' | ||||
Operating Revenue [Member] | ' | ' | ' | ' | ||||
Other Derivatives Not Designated As Hedging Instruments [Abstract] | ' | ' | ' | ' | ||||
Change in fair value | 0 | 7 | [1] | ' | ' | |||
Reclassification to realized at settlement | 0 | 10 | [1] | ' | ' | |||
Net mark-to-market gains (losses) | 0 | 17 | [1] | ' | ' | |||
Derivative [Member] | ' | ' | ' | ' | ||||
Derivatives Fair Value [Line Items] | ' | ' | ' | ' | ||||
Mark-to-market derivative assets | 754 | ' | 728 | ' | ||||
Mark-to-market derivative assets (noncurrent assets) | 534 | ' | 569 | ' | ||||
Total mark-to-market derivative assets | 1,288 | ' | 1,297 | ' | ||||
Mark-to-market derivative liabilities (current liabilities) | -249 | ' | -158 | ' | ||||
Mark-to-market derivative liabilities (noncurrent liabilities) | -271 | ' | -285 | ' | ||||
Total mark-to-market derivative liabilities | -520 | ' | -443 | ' | ||||
Total mark-to-market derivative net assets (liabilities) | 768 | ' | 854 | ' | ||||
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 | 39 | 99 | ' | ' | ||||
Total Cash Flow Hedges [Member] | ' | ' | ' | ' | ||||
Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract] | ' | ' | ' | ' | ||||
Accumulated OCI derivative gain - Beginning Balance | 120 | 368 | 368 | ' | ||||
Effective portion of changes in fair value | -1 | [2] | -1 | [3],[4] | ' | ' | ||
Accumulated OCI derivative gain - Ending Balance | 95 | 309 | ' | ' | ||||
Footnotes To Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract] | ' | ' | ' | ' | ||||
Net gain (loss) related to effective portion of changes in fair value of treasury rate locks | ' | -3 | ' | ' | ||||
Total Cash Flow Hedges [Member] | Operating Revenue One [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Cash Flow Hedge reclassified from AOCI to net income | ' | ' | ' | ' | ||||
Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract] | ' | ' | ' | ' | ||||
Reclassifications from accumulated OCI to net income | -24 | -58 | ' | ' | ||||
Exelon Generation Co L L C [Member] | ' | ' | ' | ' | ||||
Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract] | ' | ' | ' | ' | ||||
Reclassifications from accumulated OCI to net income | 4,056 | 3,141 | ' | ' | ||||
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 | 156 | ' | ' | ' | ||||
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 | 39 | 223 | ' | ' | ||||
Change in cash flow hedge ineffectiveness | 0 | 5 | ' | ' | ||||
Cash flow hedge ineffectiveness adjustment to accumulated other comprehensive income | ' | 5 | ' | ' | ||||
Derivatives Fair Value [Line Items] | ' | ' | ' | ' | ||||
Mark-to-market derivative assets | 756 | ' | 727 | ' | ||||
Mark-to-market derivative assets with affiliate (current assets) | 0 | ' | 0 | ' | ||||
Mark-to-market derivative assets (noncurrent assets) | 561 | ' | 600 | ' | ||||
Mark-to-market derivative assets with affiliate (noncurrent assets) | 0 | ' | 0 | ' | ||||
Mark-to-market derivative liabilities (current liabilities) | -238 | ' | -142 | ' | ||||
Mark-to-market derivative liabilities (noncurrent liabilities) | -131 | ' | -120 | ' | ||||
Other Derivatives Not Designated As Hedging Instruments [Abstract] | ' | ' | ' | ' | ||||
Change in fair value | -682 | -336 | ' | ' | ||||
Reclassification to realized at settlement | -48 | -67 | ' | ' | ||||
Net mark-to-market gains (losses) | -730 | -403 | ' | ' | ||||
Exelon Generation Co L L C [Member] | Operating Revenue [Member] | ' | ' | ' | ' | ||||
Proprietary Trading Activities [Abstract] | ' | ' | ' | ' | ||||
Change in fair value | -3 | -4 | ' | ' | ||||
Reclassification to realized at settlement | 1 | 6 | ' | ' | ||||
Net mark-to-market gains (losses) | -2 | 2 | ' | ' | ||||
Exelon Generation Co L L C [Member] | Operating Revenue [Member] | ' | ' | ' | ' | ||||
Other Derivatives Not Designated As Hedging Instruments [Abstract] | ' | ' | ' | ' | ||||
Change in fair value | -853 | -485 | ' | ' | ||||
Reclassification to realized at settlement | 93 | -101 | ' | ' | ||||
Net mark-to-market gains (losses) | -760 | -586 | ' | ' | ||||
Exelon Generation Co L L C [Member] | Purchased Power And Fuel [Member] | ' | ' | ' | ' | ||||
Other Derivatives Not Designated As Hedging Instruments [Abstract] | ' | ' | ' | ' | ||||
Change in fair value | 171 | 149 | ' | ' | ||||
Reclassification to realized at settlement | -141 | 34 | ' | ' | ||||
Net mark-to-market gains (losses) | 30 | 183 | ' | ' | ||||
Exelon Generation Co L L C [Member] | Derivative [Member] | ' | ' | ' | ' | ||||
Derivatives Fair Value [Line Items] | ' | ' | ' | ' | ||||
Mark-to-market derivative assets | 754 | [5] | ' | 728 | [6] | ' | ||
Mark-to-market derivative assets (noncurrent assets) | 534 | [5] | ' | 569 | [6] | ' | ||
Total mark-to-market derivative assets | 1,288 | [5] | ' | 1,297 | [6] | ' | ||
Mark-to-market derivative liabilities (current liabilities) | -236 | [5] | ' | -141 | [6] | ' | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | -116 | [5] | ' | -109 | [6] | ' | ||
Total mark-to-market derivative liabilities | -352 | [5] | ' | -250 | [6] | ' | ||
Total mark-to-market derivative net assets (liabilities) | 936 | [5] | ' | 1,047 | [6] | ' | ||
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | ' | ' | ' | ' | ||||
Derivatives Fair Value [Line Items] | ' | ' | ' | ' | ||||
Mark-to-market derivative assets | 3,401 | ' | 2,616 | ' | ||||
Mark-to-market derivative assets (noncurrent assets) | 1,240 | ' | 1,344 | ' | ||||
Total mark-to-market derivative assets | 4,641 | ' | 3,960 | ' | ||||
Mark-to-market derivative liabilities (current liabilities) | -3,348 | ' | -2,023 | ' | ||||
Mark-to-market derivative liabilities (noncurrent liabilities) | -947 | ' | -804 | ' | ||||
Total mark-to-market derivative liabilities | -4,295 | ' | -2,827 | ' | ||||
Total mark-to-market derivative net assets (liabilities) | 346 | ' | 1,133 | ' | ||||
Footnotes To Derivative Instruments In Statement Of Financial Position Fair Value [Abstract] | ' | ' | ' | ' | ||||
Current assets collateral offset | -179 | ' | 84 | ' | ||||
Noncurrent assets collateral offset | -36 | ' | 72 | ' | ||||
Current liabilities collateral offset | -252 | ' | -12 | ' | ||||
Noncurrent liabilities collateral offset | -100 | ' | 0 | ' | ||||
Total cash collateral received net of cash collateral posted | -567 | ' | 144 | ' | ||||
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 | ' | ||||
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 | 1,146 | ' | 1,476 | ' | ||||
Mark-to-market derivative assets (noncurrent assets) | 195 | ' | 285 | ' | ||||
Total mark-to-market derivative assets | 1,341 | ' | 1,761 | ' | ||||
Mark-to-market derivative liabilities (current liabilities) | -1,112 | ' | -1,410 | ' | ||||
Mark-to-market derivative liabilities (noncurrent liabilities) | -206 | ' | -293 | ' | ||||
Total mark-to-market derivative liabilities | -1,318 | ' | -1,703 | ' | ||||
Total mark-to-market derivative net assets (liabilities) | 23 | ' | 58 | ' | ||||
Exelon Generation Co L L C [Member] | Collateral And Netting [Member] | ' | ' | ' | ' | ||||
Derivatives Fair Value [Line Items] | ' | ' | ' | ' | ||||
Mark-to-market derivative assets | -3,793 | [7] | ' | -3,364 | [7] | ' | ||
Mark-to-market derivative assets (noncurrent assets) | -901 | [7] | ' | -1,060 | [7] | ' | ||
Total mark-to-market derivative assets | -4,694 | [7] | ' | -4,424 | [7] | ' | ||
Mark-to-market derivative liabilities (current liabilities) | 4,224 | [7] | ' | 3,292 | [7] | ' | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | 1,037 | [7] | ' | 988 | [7] | ' | ||
Total mark-to-market derivative liabilities | 5,261 | [7] | ' | 4,280 | [7] | ' | ||
Total mark-to-market derivative net assets (liabilities) | 567 | [7] | ' | -144 | [7] | ' | ||
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 | 119 | [8],[9] | 532 | [10],[11],[12],[13] | 532 | [10],[11],[12],[13] | ' | |
Effective portion of changes in fair value | ' | 0 | [14] | ' | ' | |||
Accumulated OCI derivative gain - Ending Balance | 95 | [8],[9] | 397 | [10],[11],[12],[13] | 119 | [8],[9] | 532 | [10],[11],[12],[13] |
Footnotes To Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract] | ' | ' | ' | ' | ||||
Unrealized gain (loss) related to fair value of swap contract | ' | 58 | ' | 133 | ||||
Net gain (loss) of reclassifications from accumulated OCI to net income related to the settlements of swap contract | ' | -75 | ' | ' | ||||
Net gains (losses) related to interest rate swaps and treasury rate locks | -3 | -16 | -15 | 20 | ||||
Exelon Generation Co L L C [Member] | Energy Related Hedges [Member] | Operating Revenue One [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Cash Flow Hedge reclassified from AOCI to net income | ' | ' | ' | ' | ||||
Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract] | ' | ' | ' | ' | ||||
Reclassifications from accumulated OCI to net income | -24 | -135 | [15] | ' | ' | |||
Commonwealth Edison Co [Member] | ' | ' | ' | ' | ||||
Derivatives Fair Value [Line Items] | ' | ' | ' | ' | ||||
Mark-to-market derivative liabilities (current liabilities) | -13 | ' | -17 | ' | ||||
Mark-to-market derivative liability with affiliate (current liability) | 0 | ' | 0 | ' | ||||
Mark-to-market derivative liabilities (noncurrent liabilities) | -155 | ' | -176 | ' | ||||
Commonwealth Edison Co [Member] | Designated as Hedging Instrument [Member] | ' | ' | ' | ' | ||||
Derivatives Fair Value [Line Items] | ' | ' | ' | ' | ||||
Mark-to-market derivative liabilities (current liabilities) | -13 | [16] | ' | -17 | ' | |||
Mark-to-market derivative liabilities (noncurrent liabilities) | -155 | [16] | ' | -176 | ' | |||
Total mark-to-market derivative liabilities | -168 | [16] | ' | -193 | ' | |||
Total mark-to-market derivative net assets (liabilities) | -168 | [16] | ' | -193 | ' | |||
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 | ' | ||||
Fair value swap contract noncurrent liability | ' | ' | $0 | ' | ||||
[1] | Prior to the merger, the five-year financial swap contract between Generation and ComEd was de-designated. As a result, all prospective changes in fair value were recorded to operating revenues and eliminated in consolidation. | |||||||
[2] | Includes $##D<gytdgleffectiveintswaplock> million of losses, net of taxes, related to the effective portion of changes in fair value of interest rate swaps and treasury rate locks. | |||||||
[3] | Includes $3 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 $##D<gpyinterestrateswaps> 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 $(179) million and $(36) million, respectively, and current and noncurrent liabilities are shown net of collateral of $(252) million and $(100) million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $567 million at March 31, 2014. | |||||||
[6] | (b)B B B B B B B B Current and noncurrent assets are shown net of collateral of $84 million and $72 million, respectively, and current and noncurrent liabilities are shown net of collateral of $(12) million and $0 million, respectively. The total cash collateral received, net of cash collateral posted and offset against mark-to-market assets and liabilities was $144 million at December 31, 2013. | |||||||
[7] | Exelon and Generation net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral.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. | |||||||
[8] | Excludes $3 million and $15 million of gains, net of taxes, related to interest rate swaps and treasury rate locks as of March 31, 2014 and December 31, 2013. | |||||||
[9] | Excludes $##D<ginterestrateswaps> million of losses and $##D<gpyglintswaptratelock> million of losses, net of taxes, related to interest rate swaps and treasury locks as of ##D<cyperiod> and ##D<pyend>, respectively. | |||||||
[10] | Includes $58 million and $133 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, as of March 31, 2013 and December 31, 2012, respectively. | |||||||
[11] | Excludes $16 million of losses and $20 million of losses, net of taxes, related to interest rate swaps and treasury rate locks as of March 31, 2013 and December 31, 2012, respectively. | |||||||
[12] | Includes $##D<gpyfyswapnot> million and $##D<gpypyefyswapnot> million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, as of ##D<pyperiod> and ##D<pyend2years>. | |||||||
[13] | Excludes $##D<gpyinterestrateswaps> million of losses and $##D<gpypyeinterestrateswaps> million of losses, net of taxes, related to interest rate swaps and treasury rate locks for the six months ended ##D<pyperiod> and year ended ##D<pyend2years>, respectively. | |||||||
[14] | Includes $##D<gpyveffswapnot> 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. | |||||||
[15] | Includes a $75 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 | |||||||
[16] | 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 $) | Mar. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Exelon Generation Co L L C [Member] | ' | ' |
Counter Party With Exposure [Abstract] | ' | ' |
Cash Collateral Held | $148 | $206 |
Letters Of Credit Held | 14 | 34 |
Credit Risk [Abstract] | ' | ' |
Financial institutions | 799 | ' |
Investor-owned utilities, marketers and power producers | 201 | ' |
Energy cooperative and municipalities | 392 | ' |
Other | 30 | ' |
Exelon Generation Co L L C [Member] | Commonwealth Edison Co Affiliate [Member] | ' | ' |
Due From Related Parties [Abstract] | ' | ' |
Net receivable from electric utility | 34 | ' |
Exelon Generation Co L L C [Member] | Total Exposure Before Credit Collateral [Member] | ' | ' |
Credit Risk [Abstract] | ' | ' |
Investment grade | 1,182 | ' |
Non-investment grade | 35 | ' |
No external ratings - internally rated - investment grade | 321 | ' |
No external ratings - internally rated - non-investment grade | 32 | ' |
Total | 1,570 | ' |
Exelon Generation Co L L C [Member] | Credit Collateral [Member] | ' | ' |
Credit Risk [Abstract] | ' | ' |
Investment grade | 117 | ' |
Non-investment grade | 22 | ' |
No external ratings - internally rated - investment grade | 0 | ' |
No external ratings - internally rated - non-investment grade | 9 | ' |
Total | 148 | ' |
Exelon Generation Co L L C [Member] | Net Exposure [Member] | ' | ' |
Credit Risk [Abstract] | ' | ' |
Investment grade | 1,065 | ' |
Non-investment grade | 13 | ' |
No external ratings - internally rated - investment grade | 321 | ' |
No external ratings - internally rated - non-investment grade | 23 | ' |
Total | 1,422 | ' |
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 | 443 | ' |
Non-investment grade | 0 | ' |
No external ratings - internally rated - investment grade | 206 | ' |
No external ratings - internally rated - non-investment grade | 0 | ' |
Total | 649 | ' |
Commonwealth Edison Co [Member] | ' | ' |
Counter Party With Exposure [Abstract] | ' | ' |
Cash Collateral Held | 19 | ' |
PECO Energy Co [Member] | ' | ' |
Natural Gas Supply And Management Agreement Credit Exposure [Abstract] | ' | ' |
Credit exposure under natural gas supply and management agreements | 1 | ' |
PECO Energy Co [Member] | PECO Energy Co Affiliate [Member] | ' | ' |
Due From Related Parties [Abstract] | ' | ' |
Net receivable from affiliated electric and gas utility | 42 | ' |
Baltimore Gas and Electric Company [Member] | ' | ' |
Natural Gas Supply And Management Agreement Credit Exposure [Abstract] | ' | ' |
Credit exposure under off system sales | 12 | ' |
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 | $41 | ' |
Derivative_Financial_Instrumen6
Derivative Financial Instruments (Collateral and Contingent-Related Features) (Details) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 | ||
In Millions, unless otherwise specified | ||||
Exelon Generation Co L L C [Member] | ' | ' | ||
Collateral And Contingent Related Features [Abstract] | ' | ' | ||
Aggregate fair value of derivatives with credit-risk-related contingent features | ($1,178) | [1] | ($1,056) | [1] |
Contractual right of offset related to derivative assets | 902 | [2] | 846 | [2] |
Net liability position after contractual right of offset | -276 | [3] | -210 | [3] |
Incremental collateral for loss of investment grade credit rating | 2,100 | 2,000 | ||
Cash collateral held | 148 | 206 | ||
Cash collateral posted | 713 | 72 | ||
Letters of credit held | 14 | 34 | ||
Letters of credit posted | 555 | 364 | ||
Master Netting Arrangements [Abstract] | ' | ' | ||
Cash collateral received not offset against net derivative positions | 8 | 10 | ||
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 | 43 | ' | ||
Baltimore Gas and Electric Company [Member] | ' | ' | ||
Collateral And Contingent Related Features [Abstract] | ' | ' | ||
Incremental collateral for loss of investment grade credit rating | $153 | ' | ||
[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 $) | 3 Months Ended | 3 Months Ended | 3 Months Ended | ||||||||||||||||||||||||||||||||||||||
Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Jan. 23, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2013 | Mar. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 14, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | |
Designated as Hedging Instrument [Member] | Designated as Hedging Instrument [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] | 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] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | ||||
Interest Rate Swap [Member] | Interest Rate Swap [Member] | Syndicated Revolver [Member] | Commercial Paper [Member] | Syndicated Revolver [Member] | Letter of Credit [Member] | Letter of Credit [Member] | Designated as Hedging Instrument [Member] | Designated as Hedging Instrument [Member] | ExgenRenewablesI425June62021[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] | Commercial Paper [Member] | Syndicated Revolver [Member] | Long Term Debt Issuances [Member] | Long Term Debt Issuances [Member] | Long Term Debt Retirements [Member] | Long Term Debt Retirements [Member] | Syndicated Revolver [Member] | Commercial Paper [Member] | Syndicated Revolver [Member] | ||||||||||||||
Fair Value Hedging [Member] | Fair Value Hedging [Member] | Foreign Exchange Contract [Member] | Interest Rate Swap [Member] | Interest Rate Swap [Member] | UpstreamGasLending221July222016[Member] | DOE Financing Project [Member] | DOE Financing Project [Member] | Non Recourse Debt [Member] | Continental Wind 6000 February 28, 2033 [Member] | Capital Lease Obligations [Member] | Capital Lease Obligations [Member] | Senior Notes [Member] | Pollution Control Notes [Member] | First Mortgage Bonds [Member] | First Mortgage Bonds [Member] | First Mortgage Bonds [Member] | Pollution Control Notes [Member] | ||||||||||||||||||||||||
DOE Project Financing, 3.092% January 2, 2037 [Member] | Floating Rate Debt [Member] | ExgenRenewablesI425June62021[Member] | Continetal Wind [Member] | Kennett Square Capital Lease, 7.83%, September 20, 2020 [Member] | Kennett Square Capital Lease, 7.83%, September 20, 2020 [Member] | SeniorSecuredNotes525January152014Member [Member] | Fixed Rate Debt [Member] | FirstMortgageBondSeries215January152019 [Member] | FirstMortgageBondSeries47January152044Member [Member] | FirstMortgageBond163January12014 [Member] | Fixed Rate Debt [Member] | ||||||||||||||||||||||||||||||
DOE Project Financing, 3.092% January 2, 2037 [Member] | |||||||||||||||||||||||||||||||||||||||||
Long-Term Debt [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Long-term debt to affiliate | ' | ' | ' | ' | ' | ' | ' | $1,517,000,000 | $1,523,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Non-Recourse Debt - Interest Rate Swap | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 240,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
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 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2.21% | ' | ' | 4.25% | 6.00% | 7.83% | 7.83% | 5.35% | 4.10% | ' | ' | ' | ' | ' | 2.15% | 4.70% | 1.63% | 5.85% | ' | ' | ' | ' | ' | ' | ' |
Minimum interest rate on long-term debt | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.03% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Maximum interest rate on long-term debt | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.03% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Long Term Debt | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,000,000 | ' | ' | 300,000,000 | 11,000,000 | 1,000,000 | ' | 500,000,000 | 20,000,000 | ' | ' | ' | ' | ' | 300,000,000 | 350,000,000 | 600,000,000 | 17,000,000 | ' | ' | ' | ' | ' | ' | ' |
Derivative, Gain on Derivative | 4,000,000 | 1,000,000 | ' | 2,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
DebtInstrumentCollateralAmount | 1,900,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Long-term Debt, Excluding Current Maturities | 18,247,000,000 | ' | 17,325,000,000 | ' | ' | ' | ' | 5,840,000,000 | 5,559,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 146,000,000 | ' | ' | ' | 1,000,000 | ' | ' | 5,707,000,000 | 5,058,000,000 | ' | ' | ' | ' | ' | ' | ' | 1,947,000,000 | 1,947,000,000 | ' | 1,746,000,000 | 1,746,000,000 | ' | ' |
Footnotes To Long-Term Debt [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Notional amount of interest rate cash flow hedge derivatives | ' | ' | ' | 1,400,000,000 | 1,275,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 164,000,000 | 195,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Line Of Credit Facility [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
LineOfCreditFacilityMaximumBorrowingCapacity | 8,400,000,000 | ' | ' | ' | ' | ' | 500,000,000 | ' | ' | ' | 5,300,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000,000 | ' | ' | ' | ' | ' | ' | 600,000,000 | ' | ' | ' | 600,000,000 |
Outstanding letters of credit | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 300,000,000 | 100,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Footnotes To Line Of Credit Facility [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Credit facility agreements with minority and community banks | ' | ' | ' | ' | ' | ' | ' | 50,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 34,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 34,000,000 | ' | ' | 5,000,000 | ' | ' | ' |
Letters of credit | ' | ' | ' | ' | ' | ' | ' | 20,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 17,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 21,000,000 | ' | ' | 1,000,000 | ' | ' | ' |
ShortTermBorrowingsAbstract | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Commercial paper borrowings | ' | ' | ' | ' | ' | ' | ' | ' | ' | 352,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 534,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 69,000,000 | ' |
Short-term debt outstanding amount | 980,000,000 | ' | 341,000,000 | ' | ' | ' | ' | 377,000,000 | 22,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 534,000,000 | 184,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 69,000,000 | 135,000,000 | ' | ' |
Credit Agreements [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Additional amounts available upon request under current credit facilities | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 500,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Basis points adders for prime-based borrowings | ' | ' | ' | ' | ' | 0.275 | ' | 0.275 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.075 | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | 0 | ' | ' | ' |
Basis points adders for LIBOR-based borrowings | ' | ' | ' | ' | ' | 1.275 | ' | 1.275 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1.075 | ' | ' | ' | ' | ' | ' | ' | ' | 0.9 | ' | ' | 1 | ' | ' | ' |
Amount Of Aggregate Letters of Credit Available | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 500,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Revolver Under Amendment | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $1,000,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Income_Taxes_Details
Income Taxes (Details) (USD $) | 3 Months Ended | 12 Months Ended | 3 Months Ended | 12 Months Ended | 3 Months Ended | 12 Months Ended | 3 Months Ended | 3 Months Ended | 3 Months Ended | ||||||||||||||||||||
Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2012 | Mar. 31, 2011 | Dec. 31, 2012 | Dec. 31, 2010 | Dec. 31, 2013 | Dec. 31, 1999 | Mar. 31, 2011 | Dec. 31, 2011 | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2012 | Mar. 31, 2011 | Dec. 31, 2012 | Dec. 31, 2013 | Mar. 31, 2011 | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2011 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2011 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2013 | |||
Deferred Tax Impact [Member] | Deferred Tax Impact [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] | 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] | |||||||||||
Deferred Tax Impact [Member] | |||||||||||||||||||||||||||||
Effective Income Tax Rate Reconciliation | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
U.S. Federal statutory rate | 35.00% | 35.00% | ' | ' | ' | ' | ' | ' | ' | ' | 35.00% | 35.00% | ' | ' | ' | ' | ' | 35.00% | 35.00% | ' | ' | 35.00% | 35.00% | ' | ' | 35.00% | 35.00% | ||
Increase (decrease) due to: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
State income taxes, net of Federal income tax benefit | -57.60% | 68.00% | ' | ' | ' | ' | ' | ' | ' | ' | 9.70% | 82.00% | ' | ' | ' | ' | ' | 5.50% | 5.80% | ' | ' | 1.20% | 2.80% | ' | ' | 5.20% | 5.70% | ||
Qualified nuclear decommissioning trust fund income (losses) | 44.20% | 62.00% | ' | ' | ' | ' | ' | ' | ' | ' | -4.60% | -192.30% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Domestic production activities deduction | -27.80% | -2.40% | ' | ' | ' | ' | ' | ' | ' | ' | 2.90% | 7.40% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Tax exempt income | ' | -1.60% | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4.80% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Health Care Reform Legislation | 1.30% | 2.20% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.10% | -0.50% | ' | ' | ' | ' | ' | ' | 0.20% | 0.40% | ||
Amortization of investment tax credit | -18.00% | -25.80% | ' | ' | ' | ' | ' | ' | ' | ' | 1.70% | 75.60% | ' | ' | ' | ' | ' | -0.30% | 0.40% | ' | ' | -0.10% | -0.10% | ' | ' | -0.20% | -0.20% | ||
Plant basis differences | -31.40% | -24.90% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -0.60% | 0.90% | ' | ' | -8.70% | -6.70% | ' | ' | -0.60% | -0.60% | ||
Production Tax Credits | -36.50% | -21.70% | ' | ' | ' | ' | ' | ' | ' | ' | 3.80% | 67.20% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Other | -47.70% | 7.40% | ' | ' | ' | ' | ' | ' | ' | ' | 3.30% | -74.10% | [1] | ' | ' | ' | ' | ' | 0.20% | 0.10% | [1] | ' | ' | 0.20% | 0.10% | ' | ' | 0.10% | 0.40% |
Effective income tax rate | -138.50% | 98.20% | ' | ' | ' | ' | ' | ' | ' | ' | 51.80% | 5.60% | [1] | ' | ' | ' | ' | ' | 39.90% | 41.70% | ' | ' | 27.60% | 31.10% | ' | ' | 39.70% | 40.70% | |
Accounting for Uncertainty in Income Taxes [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Unrecognized tax benefits that if recognized would affect the effective tax rate | $1,860,000,000 | ' | ' | ' | ' | ' | $2,175,000,000 | ' | ' | ' | $1,394,000,000 | ' | ' | ' | ' | $1,415,000,000 | ' | $155,000,000 | ' | ' | $324,000,000 | $44,000,000 | ' | ' | $44,000,000 | ' | ' | ||
Information by nature of uncertainty related to unrecognized tax benefits | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 225,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
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 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 155,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
IRS asserted penalties for understatement of tax | 265,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 170,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Potential tax and interest from a successful IRS challenge of the like-kind exchange transaction position | 840,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 300,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
IRS asserted penalties for understatement of tax related to like-kind exchange | 87,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Status Of Like Kind Exchange Position [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Receivable from Exelon intercompany money pool | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' | ' | 44,000,000 | ' | 172,000,000 | ' | ' | ' | 0 | ' | ' | 0 | ' | ' | ||
FIN 48 Tax Remeasurement [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
FIN 48 Tax Remeasurement Interest Expense | ' | ' | ' | 65,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 36,000,000 | ' | ' | ' | 22,000,000 | ' | ' | ' | ||
FIN 48 Tax Remeasurement Current Tax Expense (Benefit) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 70,000,000 | ' | ' | ' | ' | ' | 70,000,000 | ' | ' | ' | ' | ' | ' | ' | ||
Tax Settlement [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Payment to IRS for open tax positions | ' | ' | ' | ' | ' | 302,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Income tax benefit recorded as a result of re-apportionment of state income taxes [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Gross Deferred Income tax benefit recorded as a result of re-apportionment of state income taxes | ' | ' | 116,000,000 | ' | 3,000,000 | ' | ' | ' | ' | 8,000,000 | ' | ' | 14,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Gross Deferred Income tax expense recorded as a result of re-apportionment of state income taxes | ' | ' | ' | ' | ' | ' | ' | ' | 22,000,000 | 1,000,000 | ' | ' | ' | ' | 7,000,000 | ' | 11,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Deferred state tax liability resulting from purchase accounting | ' | ' | 44,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 14,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
DeferredStateTaxAssetFromStateTaxApportionment | ' | ' | 72,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
TaxesPayableCurrent | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Taxes Payable Current | 285,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Income Tax Expense Benefit Continuing Operations [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Income Tax Expense (Benefit) | ($54,000,000) | $56,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ($199,000,000) | ($1,000,000) | ' | ' | ' | ' | ' | $65,000,000 | ($58,000,000) | ' | ' | $34,000,000 | $55,000,000 | ' | ' | $58,000,000 | $55,000,000 | ||
[1] | B Generation recognized a loss before income taxes for the three months ended March 31, 2014. As a result, positive percentages represent an income tax benefit for Generation for the three months ended March 31, 2014 |
Asset_Retirement_Obligation_De
Asset Retirement Obligation (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | ||
Nuclear Decommissioning Trust Fund Investments [Abstract] | ' | ' | ' | ||
Shortfall of decommissioning funds with recourse | $50 | ' | ' | ||
Percent of additional decommissioning shortfall with recourse | 5.00% | ' | ' | ||
NDT fund investments | 8,215 | ' | 8,071 | ||
NRC Minimum Funding Requirements [Abstract] | ' | ' | ' | ||
Additional NRC funding assurance parent guarantees | ' | ' | 115 | ||
Nuclear Decommissioning Obligation [Line Items] | ' | ' | ' | ||
Pledged assets for Zion Station decommissioning | 429 | ' | 458 | ||
Total payable to ZionSolutions | 385 | [1] | ' | 414 | [1] |
Current payable to ZionSolutions | 103 | [2] | ' | 109 | [2] |
Zion Station decommissioning costs withdrawn | 537 | [3] | ' | 498 | [3] |
Unrealized Losses On Nuclear Decommissioning Trust Fund Investment [Line Items] | ' | ' | ' | ||
Net unrealized gains (losses) on decommissioning trust funds - Regulatory Agreement Units | 61 | [4] | ' | 195 | [4] |
Net unrealized gains (losses) on decommissioning trust funds - Non-Regulatory Agreement Units | 13 | [5],[6] | ' | 64 | [5],[6] |
Footnotes To Unrealized Gains Losses On NDT Funds [Abstract] | ' | ' | ' | ||
Gains on Zion Station Pledged Assets | 10 | 2 | ' | ||
Nuclear Decommissioning Asset Retirement Obligation [Member] | ' | ' | ' | ||
Asset Retirement Obligation Roll Forward Analysis [Roll Forward] | ' | ' | ' | ||
ARO beginning balance | 4,855 | [7] | ' | ' | |
Accretion expense | 66 | ' | ' | ||
Costs incurred to decommission retired plants | -1 | ' | ' | ||
ARO ending balance | 4,920 | [7] | ' | ' | |
Footnotes To Asset Retirement Obligation [Abstract] | ' | ' | ' | ||
Current Portion of ARO | 9 | ' | 9 | ||
Exelon Generation Co L L C [Member] | ' | ' | ' | ||
Nuclear Decommissioning Trust Fund Investments [Abstract] | ' | ' | ' | ||
Shortfall of decommissioning funds with recourse | 50 | ' | ' | ||
Percent of additional decommissioning shortfall with recourse | 5.00% | ' | ' | ||
NDT fund investments | 8,215 | ' | 8,071 | ||
NRC Minimum Funding Requirements [Abstract] | ' | ' | ' | ||
Additional NRC funding assurance parent guarantees | ' | ' | 115 | ||
Nuclear Decommissioning Obligation [Line Items] | ' | ' | ' | ||
Pledged assets for Zion Station decommissioning | 429 | ' | 458 | ||
Total payable to ZionSolutions | 385 | [1] | ' | 414 | [1] |
Current payable to ZionSolutions | 103 | [2] | ' | 109 | [2] |
Zion Station decommissioning costs withdrawn | 537 | [3] | ' | 498 | [3] |
Unrealized Losses On Nuclear Decommissioning Trust Fund Investment [Line Items] | ' | ' | ' | ||
Net unrealized gains (losses) on decommissioning trust funds - Regulatory Agreement Units | 61 | [4] | ' | 195 | [4] |
Net unrealized gains (losses) on decommissioning trust funds - Non-Regulatory Agreement Units | 13 | [5],[6] | ' | 64 | [5],[6] |
Footnotes To Unrealized Gains Losses On NDT Funds [Abstract] | ' | ' | ' | ||
Gains on Zion Station Pledged Assets | 10 | 2 | ' | ||
Exelon Generation Co L L C [Member] | Nuclear Decommissioning Asset Retirement Obligation [Member] | ' | ' | ' | ||
Asset Retirement Obligation Roll Forward Analysis [Roll Forward] | ' | ' | ' | ||
ARO beginning balance | 4,855 | [7] | ' | ' | |
Accretion expense | 66 | ' | ' | ||
Costs incurred to decommission retired plants | -1 | ' | ' | ||
ARO ending balance | 4,920 | [7] | ' | ' | |
Footnotes To Asset Retirement Obligation [Abstract] | ' | ' | ' | ||
Current Portion of ARO | $9 | ' | $9 | ||
[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 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 $ 10 million and $2 million of net unrealized gains related to the Zion Station pledged assets for the three months ended March 31, 2014 and 2013, 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 $9 million as the current portion of the ARO at March 31, 2014 and December 31, 2013 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 | 12 Months Ended | |||
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | ||
Nuclear Decommissioning Trust Fund Investments [Abstract] | ' | ' | ' | ||
NDT fund investments | $8,215 | ' | $8,071 | ||
Current annual recovery of decommissioning costs | 24 | ' | ' | ||
Shortfall of decommissioning funds with recourse | 50 | ' | ' | ||
Decommissioning Shortfall Percentage | 5.00% | ' | ' | ||
Decommissioning [Abstract] | ' | ' | ' | ||
Pledged assets for Zion Station decommissioning | 429 | ' | 458 | ||
Total payable to ZionSolutions | 385 | [1] | ' | 414 | [1] |
Current payable to ZionSolutions | 103 | [2] | ' | 109 | [2] |
Zion Station decommissioning costs withdrawn | 537 | [3] | ' | 498 | [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 | 61 | [4] | ' | 195 | [4] |
Net unrealized gains (losses) on decommissioning trust funds - Non-Regulatory Agreement Units | 13 | [5],[6] | ' | 64 | [5],[6] |
Footnotes To Unrealized Gains Losses On NDT Funds [Abstract] | ' | ' | ' | ||
Gains on Zion Station Pledged Assets | 10 | 2 | ' | ||
Nuclear Decommissioning Asset Retirement Obligation [Member] | ' | ' | ' | ||
Asset Retirement Obligation Roll Forward Analysis [Roll Forward] | ' | ' | ' | ||
ARO beginning balance | 4,855 | [7] | ' | ' | |
Accretion expense | 66 | ' | ' | ||
Costs incurred to decommission retired plants | -1 | ' | ' | ||
ARO ending balance | 4,920 | [7] | ' | ' | |
Footnotes To Asset Retirement Obligation [Abstract] | ' | ' | ' | ||
Current Portion of ARO | 9 | ' | 9 | ||
Exelon Generation Co L L C [Member] | ' | ' | ' | ||
Nuclear Decommissioning Trust Fund Investments [Abstract] | ' | ' | ' | ||
NDT fund investments | 8,215 | ' | 8,071 | ||
Shortfall of decommissioning funds with recourse | 50 | ' | ' | ||
Decommissioning Shortfall Percentage | 5.00% | ' | ' | ||
Decommissioning [Abstract] | ' | ' | ' | ||
Pledged assets for Zion Station decommissioning | 429 | ' | 458 | ||
Total payable to ZionSolutions | 385 | [1] | ' | 414 | [1] |
Current payable to ZionSolutions | 103 | [2] | ' | 109 | [2] |
Zion Station decommissioning costs withdrawn | 537 | [3] | ' | 498 | [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 | 61 | [4] | ' | 195 | [4] |
Net unrealized gains (losses) on decommissioning trust funds - Non-Regulatory Agreement Units | 13 | [5],[6] | ' | 64 | [5],[6] |
Footnotes To Unrealized Gains Losses On NDT Funds [Abstract] | ' | ' | ' | ||
Gains on Zion Station Pledged Assets | 10 | 2 | ' | ||
Exelon Generation Co L L C [Member] | Nuclear Decommissioning Asset Retirement Obligation [Member] | ' | ' | ' | ||
Asset Retirement Obligation Roll Forward Analysis [Roll Forward] | ' | ' | ' | ||
ARO beginning balance | 4,855 | [7] | ' | ' | |
Accretion expense | 66 | ' | ' | ||
Costs incurred to decommission retired plants | -1 | ' | ' | ||
ARO ending balance | 4,920 | [7] | ' | ' | |
Footnotes To Asset Retirement Obligation [Abstract] | ' | ' | ' | ||
Current Portion of ARO | 9 | ' | 9 | ||
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 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 $ 10 million and $2 million of net unrealized gains related to the Zion Station pledged assets for the three months ended March 31, 2014 and 2013, 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 $9 million as the current portion of the ARO at March 31, 2014 and December 31, 2013 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 | 8 Months Ended | ||||||||||||||||||
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2014 | ||
Business Services Company [Member] | Business Services Company [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Pension Plans Defined Benefit [Member] | Pension Plans Defined Benefit [Member] | Other Postretirement Benefit Plans Defined Benefit [Member] | Other Postretirement Benefit Plans Defined Benefit [Member] | Other Postretirement Benefit Plans Defined Benefit [Member] | Other Postretirement Benefit Plans Defined Benefit [Member] | |||||
Subsequent Event [Member] | NetPeriodicBenefitCostDecrease [Member] | |||||||||||||||||||
Subsequent Event [Member] | ||||||||||||||||||||
Change in benefit obligation: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Service cost | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $69 | $80 | $33 | $41 | ' | ' | ||
Interest cost | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 183 | 163 | 55 | 48 | ' | ' | ||
Plan amendments | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -125 | ||
DefinedBenefitPlanBenefitObligationPeriodIncreaseDecrease | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -800 | ' | ||
Components of net periodic benefit cost: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Service cost | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 69 | 80 | 33 | 41 | ' | ' | ||
Interest cost | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 183 | 163 | 55 | 48 | ' | ' | ||
Amortization of actuarial gain (loss) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 105 | 140 | 8 | 20 | ' | ' | ||
Prior service cost (credit) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3 | 3 | -4 | -4 | ' | ' | ||
Expected return on assets | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -241 | -253 | -38 | -33 | ' | ' | ||
Net periodic benefit cost | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 119 | 133 | 54 | 72 | ' | ' | ||
Changes in plan assets and benefit obligations recognized in OCI and regulatory assets: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Changes in plan assets and benefit obligations recognized in OCI | -13 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Increase in regulatory assets due valuation received by Exelon for its legacy pension and other postretirement benefit obligations. | 34 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Increase in regulatory liabilities due to updated valuation of Exelon's legacy pension and postretirement benefit obligations | 5 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Pension And Other Postretirement Benefit Contributions [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Pension and non-pension postretirement benefit contributions | 472 | 267 | ' | ' | 191 | 115 | 233 | 118 | 11 | 11 | 5 | 5 | ' | ' | ' | ' | ' | ' | ||
Defined Benefit Plan Expense Included In Capital And Operational And Maintenance Expense [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Amount included in capital and operating & maintenance expense | ' | ' | 14 | [1] | 17 | [1] | 75 | 87 | 56 | 77 | 12 | 11 | 16 | 13 | ' | ' | ' | ' | ' | ' |
Defined Contribution Plan Contributions By Employer [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Savings plan matching contributions | 29 | 22 | 3 | 2 | 14 | 11 | 7 | 5 | 2 | 2 | 3 | 2 | ' | ' | ' | ' | ' | ' | ||
Valuation Adjustment Impact [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Benefit obligation increase (decrease) reflecting actual census data | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $35 | ' | $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. |
Retirement_Benefits_Assumption
Retirement Benefits - Assumptions Used In Calculations (Details) | 3 Months Ended |
Mar. 31, 2014 | |
Pension Plans Defined Benefit [Member] | ' |
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Net Periodic Benefit Cost [Abstract] | ' |
Expected return on plan assets | 7.00% |
Discount rate | 4.80% |
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 | 6.59% |
Discount rate | 4.90% |
Retirement_Benefits_Fair_Value
Retirement Benefits - Fair Value Recurring Basis (Details) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 | ||
In Millions, unless otherwise specified | ||||
Defined Benefit Plan Disclosure [Line Items] | ' | ' | ||
Cash equivalents | $518 | [1] | $1,230 | [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 $) | Mar. 31, 2014 |
In Millions, unless otherwise specified | |
Defined Benefit Plan Contributions [Abstract] | ' |
Expected qualified pension plan contributions | $264 |
Expected non-qualified pension plan contributions | 12 |
Expected other postretirement benefit plan contributions | 430 |
Exelon Generation Co L L C [Member] | ' |
Defined Benefit Plan Contributions [Abstract] | ' |
Expected qualified pension plan contributions | 118 |
Expected non-qualified pension plan contributions | 5 |
Expected other postretirement benefit plan contributions | 168 |
Commonwealth Edison Co [Member] | ' |
Defined Benefit Plan Contributions [Abstract] | ' |
Expected qualified pension plan contributions | 119 |
Expected non-qualified pension plan contributions | 1 |
Expected other postretirement benefit plan contributions | 197 |
PECO Energy Co [Member] | ' |
Defined Benefit Plan Contributions [Abstract] | ' |
Expected qualified pension plan contributions | 11 |
Expected other postretirement benefit plan contributions | 19 |
Baltimore Gas and Electric Company [Member] | ' |
Defined Benefit Plan Contributions [Abstract] | ' |
Expected non-qualified pension plan contributions | 1 |
Expected other postretirement benefit plan contributions | $17 |
Severance_and_Plant_Retirement
Severance and Plant Retirements (Details) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Corporate Restructuring Severance Benefit Obligation [Line Items] | ' | ' |
Severance charges recorded | $4 | $1 |
Restructuring Reserve [Roll Forward] | ' | ' |
Restructuring Reserve, Period Start | 53 | ' |
Payments | 12 | ' |
Restructuring Reserve, Period End | 41 | ' |
Business Acquisition, Costs Recognized Post Merger [Abstract] | ' | ' |
Business Acquisition Charitable Contributions Per Year | 7 | ' |
Plant Retirement Cost [Abstract] | ' | ' |
Inventory write down related to plant retirements | 2 | ' |
Exelon Generation Co L L C [Member] | ' | ' |
Corporate Restructuring Severance Benefit Obligation [Line Items] | ' | ' |
Severance charges recorded | 4 | 0 |
Restructuring Reserve [Roll Forward] | ' | ' |
Restructuring Reserve, Period Start | 10 | ' |
Payments | 1 | ' |
Restructuring Reserve, Period End | 9 | ' |
Plant Retirement Cost [Abstract] | ' | ' |
Inventory write down related to plant retirements | 2 | ' |
Commonwealth Edison Co [Member] | ' | ' |
Corporate Restructuring Severance Benefit Obligation [Line Items] | ' | ' |
Severance charges recorded | 0 | 1 |
Restructuring Reserve [Roll Forward] | ' | ' |
Restructuring Reserve, Period Start | 0 | ' |
Payments | 0 | ' |
Restructuring Reserve, Period End | 0 | ' |
PECO Energy Co [Member] | ' | ' |
Corporate Restructuring Severance Benefit Obligation [Line Items] | ' | ' |
Severance charges recorded | 0 | 0 |
Restructuring Reserve [Roll Forward] | ' | ' |
Restructuring Reserve, Period Start | 0 | ' |
Payments | 0 | ' |
Restructuring Reserve, Period End | 0 | ' |
Baltimore Gas and Electric Company [Member] | ' | ' |
Corporate Restructuring Severance Benefit Obligation [Line Items] | ' | ' |
Severance charges recorded | 0 | 0 |
Restructuring Reserve [Roll Forward] | ' | ' |
Restructuring Reserve, Period Start | 6 | ' |
Payments | 2 | ' |
Restructuring Reserve, Period End | $4 | ' |
Preferred_Securities_Details
Preferred Securities (Details) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | Preferred Stock [Member] | PECO Energy Co [Member] |
Temporary Equity [Line Items] | ' | ' |
Dollar amount | $87 | $0 |
StockBased_Compensation_Plans_1
Stock-Based Compensation Plans (Details) (USD $) | 3 Months Ended | ||
In Millions, except Share data, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 |
Common Stock [Abstract] | ' | ' | ' |
Common Stock without par - Authorized | 2,000,000,000 | ' | 2,000,000,000 |
Common Stock without par - Outstanding | 858,721,507 | ' | 857,000,000 |
Share Based Compensation Components [Abstract] | ' | ' | ' |
Stock-based compensation costs | $46 | $39 | ' |
Exelon Generation Co L L C [Member] | ' | ' | ' |
Share Based Compensation Components [Abstract] | ' | ' | ' |
Stock-based compensation costs | 0 | 4 | ' |
Commonwealth Edison Co [Member] | ' | ' | ' |
Share Based Compensation Components [Abstract] | ' | ' | ' |
Stock-based compensation costs | 0 | 1 | ' |
PECO Energy Co [Member] | ' | ' | ' |
Share Based Compensation Components [Abstract] | ' | ' | ' |
Stock-based compensation costs | 0 | 1 | ' |
Baltimore Gas and Electric Company [Member] | ' | ' | ' |
Share Based Compensation Components [Abstract] | ' | ' | ' |
Stock-based compensation costs | $0 | $1 | ' |
Earnings_Per_Share_and_Equity_2
Earnings Per Share and Equity (Details) (USD $) | 3 Months Ended | ||
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 |
Earnings Per Share And Equity Additional Narrative Information [Abstract] | ' | ' | ' |
Stock options not included in the calculation of diluted common shares outstanding | 18 | 0 | ' |
Treasury Stock, Shares held | 35 | ' | 35 |
Treasury stock, at cost | $2,327 | ' | $2,327 |
Earnings Per Share Diluted | ' | ' | ' |
Net income on common stock | $90 | ($4) | ' |
Average common shares outstanding - basic | 858 | 855 | ' |
Assumed exercise of stock options, performance share awards and restricted stock | 3 | 0 | ' |
Average common shares outstanding - diluted | 861 | 855 | ' |
Changes_in_Accumulated_Other_C2
Changes in Accumulated Other Comprehensive Income (Changes in accumulated other comprehensive income by component)(Details) (USD $) | 3 Months Ended | 3 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | ||||||||||||||||||||||||||||||||
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 Net Unrealized Investment Gain Loss [Member] | Accumulated Net Unrealized Investment Gain Loss [Member] | Accumulated Defined Benefit Plans Adjustment [Member] | Accumulated Defined Benefit Plans Adjustment [Member] | Accumulated Translation Adjustment [Member] | Accumulated Translation Adjustment [Member] | Accumulated Equity Investment [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] | 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] | 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] | |||||||||||||||||||||||||||||||||||
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 Net Unrealized Investment Gain Loss [Member] | Accumulated Net Unrealized Investment Gain Loss [Member] | Accumulated Defined Benefit Plans Adjustment [Member] | Accumulated Defined Benefit Plans Adjustment [Member] | Accumulated Translation Adjustment [Member] | Accumulated Translation Adjustment [Member] | Accumulated Equity Investment [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 Unrealized Investment Gain Loss [Member] | Accumulated Net Unrealized Investment Gain Loss [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Accumulated Other Comprehensive Income Loss [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance | ($2,040) | [1] | ($2,767) | [1] | $120 | [1] | $368 | [1] | $2 | [1] | ' | ($2,260) | [1] | ($3,137) | [1] | ($10) | [1] | ' | $108 | [1] | $2 | [1] | ' | $214 | [1] | $513 | [1] | $114 | [1] | $513 | [1] | $2 | [1] | ($1) | [1] | ($19) | [1] | ($19) | [1] | ($10) | [1] | ' | $108 | [1] | $20 | [1] | ' | $0 | $0 | $1 | [1] | $1 | [1] | $1 | [1] | $1 | [1] | $1 | [1] | $1 | [1] | $1 | [1] | $1 | [1] | |||
OCI before reclassifications | -8 | [1] | 100 | [1] | -1 | [1] | ' | 0 | [1] | -1 | [1] | -13 | [1] | 76 | [1] | -5 | [1] | -1 | [1] | 11 | [1] | 26 | [1] | ' | 2 | [1] | 29 | [1] | -1 | [1] | 5 | [1] | -3 | [1] | -1 | [1] | ' | ' | -5 | [1] | -1 | [1] | 11 | [1] | 26 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||
Amounts reclassified from AOCI | 12 | [1],[2] | -6 | [1],[3] | -24 | [1],[2] | -58 | [1],[3] | ' | ' | 35 | [1],[2] | 50 | [1],[3] | ' | ' | 1 | [1],[2] | 2 | [1],[3] | ' | -23 | [1],[2] | -133 | [1],[3] | -24 | [1],[2] | -135 | [1],[3] | ' | ' | ' | ' | ' | ' | 1 | [1],[2] | 2 | [1],[3] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||
Net current-period OCI | 4 | [1] | 94 | [1] | -25 | [1] | -58 | [1] | 0 | [1] | -1 | [1] | 22 | [1] | 126 | [1] | -5 | [1] | -1 | [1] | 12 | [1] | 28 | [1] | ' | -21 | [1] | -104 | [1] | -25 | [1] | -130 | [1] | -3 | [1] | -1 | [1] | ' | ' | -5 | [1] | -1 | [1] | 12 | [1] | 28 | [1] | -21 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance | -2,036 | [1] | -2,673 | [1] | 95 | [1] | 310 | [1] | 2 | [1] | -1 | [1] | -2,238 | [1] | -3,011 | [1] | -15 | [1] | -1 | [1] | 120 | [1] | 30 | [1] | ' | 193 | [1] | 409 | [1] | 89 | [1] | 383 | [1] | -1 | [1] | -2 | [1] | -19 | [1] | -19 | [1] | -15 | [1] | -1 | [1] | 120 | [1] | 48 | [1] | ' | 0 | 0 | 1 | [1] | 1 | [1] | 1 | [1] | 1 | [1] | 1 | [1] | 1 | [1] | 1 | [1] | 1 | [1] |
OtherComprehensiveIncomeLossTaxParentheticalDisclosuresAbstract | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||||
Prior service costs | -1 | 0 | ' | ' | ' | ' | -2 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||
Actuarial loss reclassified to periodic cost, taxes | 23 | 32 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||||
Pension and non-pension postretirement benefit plan valuation adjustment, taxes | -7 | 49 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||||
Change in unrealized gain (loss) on cash flow hedges, taxes | 18 | 33 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 19 | 86 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||||
Change in unrealized gain (loss) on marketable securities, taxes | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||||
Change in unrealized gain (loss) on equity investments taxes | -7 | -18 | ' | ' | ' | ' | ' | ' | ' | ' | -1 | ' | ' | -7 | -18 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||||
Other comprehensive income, income taxes | ($6) | ($66) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $6 | $10 | $68 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $10 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||||||||||||||||||
[1] | (a) All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[2] | (b) This accumulated other comprehensive income component is included in the computation of net periodic pension and OPEB cost (see Note 11 for additional details). | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[3] | (b) See tables following changes in accumulated other comprehensive income tables for details about these reclassifications. |
Changes_in_Accumulated_Other_C3
Changes in Accumulated Other Comprehensive Income (Reclassification out of Accumulated Other Comprehensive Income)(Details) (USD $) | 3 Months Ended | |||
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 | ||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ||
Operating revenues | $7,237 | [1] | $6,082 | [1] |
Interest Expense | 217 | 617 | ||
Other income and deductions | -124 | -451 | ||
Income before income taxes | 39 | 57 | ||
Income taxes | -54 | 56 | ||
Net income (loss) | 93 | 1 | ||
Other Comprehensive Income Loss Reclassification Adjustment From AOCI Pension And Other Postretirement Benefit PlansTax [Abstract] | ' | ' | ||
Prior service costs | -1 | 0 | ||
Loss on equity method investments | -19 | -9 | ||
Reclassification out of Accumulated Other Comprehensive Income [Member] | ' | ' | ||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ||
Net income (loss) | -12 | [2] | 6 | [2] |
Accumulated Net Gain Loss From Designated Or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | ' | ' | ||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ||
Income before income taxes | 39 | [2] | 98 | [2] |
Income taxes | -15 | [2] | -40 | [2] |
Net income (loss) | 24 | [2] | ' | |
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 | 39 | [2] | 99 | [2] |
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 | [2] | |
Accumulated Net Gain Loss From Designated Or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Derivative [Member] | ' | ' | ||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ||
Income taxes | ' | 58 | [2] | |
Accumulated Defined Benefit Plans Adjustment [Member] | ' | ' | ||
Other Comprehensive Income Loss Reclassification Adjustment From AOCI Pension And Other Postretirement Benefit PlansTax [Abstract] | ' | ' | ||
Prior service costs | -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 | -58 | [2] | -83 | [2] |
Income taxes | 23 | [2] | 33 | [2] |
Net income (loss) | -35 | [2] | -50 | [2] |
Other Comprehensive Income Loss Reclassification Adjustment From AOCI Pension And Other Postretirement Benefit PlansTax [Abstract] | ' | ' | ||
Deferred compensation unit | 0 | [2] | ' | |
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 | -56 | [2] | -83 | [2] |
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 | -1 | -3 | [2] | |
Income taxes | 0 | 1 | [2] | |
Net income (loss) | -1 | -2 | [2] | |
Other Comprehensive Income Loss Reclassification Adjustment From AOCI Pension And Other Postretirement Benefit PlansTax [Abstract] | ' | ' | ||
Loss on equity method investments | ' | -3 | [2] | |
Exelon Generation Co L L C [Member] | ' | ' | ||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ||
Operating revenues | 4,390 | 3,533 | ||
Interest Expense | 73 | 65 | ||
Other income and deductions | 5 | 46 | ||
Income before income taxes | -384 | -18 | ||
Income taxes | -199 | -1 | ||
Net income (loss) | -185 | -17 | ||
Other Comprehensive Income Loss Reclassification Adjustment From AOCI Pension And Other Postretirement Benefit PlansTax [Abstract] | ' | ' | ||
Loss on equity method investments | -19 | -9 | ||
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) | 23 | [2] | 133 | [2] |
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] | ' | ' | ||
Income before income taxes | 39 | [2] | 223 | [2] |
Income taxes | -15 | [2] | -88 | [2] |
Net income (loss) | 24 | [2] | ' | |
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 | 39 | [2] | 223 | [2] |
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 | ' | 0 | ||
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] | Derivative [Member] | ' | ' | ||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ||
Income taxes | ' | 135 | [2] | |
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 | -1 | -3 | [2] | |
Income taxes | 0 | 1 | [2] | |
Net income (loss) | -1 | -2 | [2] | |
Other Comprehensive Income Loss Reclassification Adjustment From AOCI Pension And Other Postretirement Benefit PlansTax [Abstract] | ' | ' | ||
Loss on equity method investments | -1 | -3 | [2] | |
Commonwealth Edison Co [Member] | ' | ' | ||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ||
Operating revenues | 1,134 | 1,160 | ||
Interest Expense | 77 | 350 | ||
Other income and deductions | -75 | -348 | ||
Income before income taxes | 163 | -139 | ||
Income taxes | 65 | -58 | ||
Net income (loss) | 98 | -81 | ||
PECO Energy Co [Member] | ' | ' | ||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ||
Operating revenues | 993 | 895 | ||
Interest Expense | 25 | 26 | ||
Other income and deductions | -26 | -26 | ||
Income before income taxes | 123 | 177 | ||
Income taxes | 34 | 55 | ||
Net income (loss) | 89 | 122 | ||
Baltimore Gas and Electric Company [Member] | ' | ' | ||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ||
Operating revenues | 1,054 | 880 | ||
Interest Expense | 23 | 29 | ||
Other income and deductions | -23 | -28 | ||
Income before income taxes | 146 | 135 | ||
Income taxes | 58 | 55 | ||
Net income (loss) | $88 | $80 | ||
[1] | For the ##D<curmonth> months ended ##D<cyperiod> and ##D<pyfiscal>, utility taxes of $##D<gcytdutiltax> million and $##D<gpytdutiltax> million, respectively, are included in revenues and expenses for Generation. For the ##D<curmonth> months ended ##D<cyperiod> and ##D<pyfiscal>, utility taxes of $##D<ccytdutiltax> million and $##D<cpytdutiltax> million, respectively, are included in revenues and expenses for ComEd. For the ##D<curmonth> months ended ##D<cyperiod> and ##D<pyfiscal>, utility taxes of $##D<pcytdutiltax> million and $##D<ppytdutiltax> million, respectively, are included in revenues and expenses for PECO. For the ##D<curmonth> months ended ##D<cyperiod> and period of March 12, 2012 through ##D<pyperiod>, utility taxes of $##D<bcytdutiltax> million and $##D<bpytdutiltax> million, respectively, are included in revenues and expenses for BGE. | |||
[2] | (a) All amounts are net of tax. Amounts in parenthesis represent a decrease in net income. | |||
[3] | (a) All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income. |
Commitments_and_Contingencies_2
Commitments and Contingencies (Details) (USD $) | 3 Months Ended | 12 Months Ended | 0 Months Ended | 3 Months Ended | 1 Months Ended | 3 Months Ended | 3 Months Ended | 3 Months Ended | 3 Months Ended | 0 Months Ended | 3 Months Ended | 0 Months Ended | 3 Months Ended | 3 Months Ended | 3 Months Ended | 3 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Apr. 12, 2012 | Feb. 28, 2012 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Jan. 31, 2013 | Oct. 31, 2007 | Mar. 31, 2014 | Dec. 31, 2013 | Jan. 31, 2005 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Jan. 31, 2005 | Mar. 31, 2014 | Mar. 31, 2014 | Jul. 11, 2011 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2012 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | ||||||||||||||||||||||
T | Other Purchase Obligations [Member] | Cotter Corporation [Member] | Cotter Corporation [Member] | Total Accrual For Environmental Loss Contingencies [Member] | Total Accrual For Environmental Loss Contingencies [Member] | Accrual For MGP Investigation And Remediation [Member] | Accrual For MGP Investigation And Remediation [Member] | Financial Standby Letter of Credit [Member] | Sithe Guarantee [Member] | Nuclear Insurance Premiums [Member] | Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | 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] | 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 | 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] | FourmileConstructionMember [Member] | Maximum [Member] | Maximum [Member] | Minimum [Member] | Minimum [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] | Nuclear Insurance Premiums [Member] | Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member] | Customers | ElectricGenerationStation | Renewable Energy Including Renewable Energy Credits [Member] | Other Purchase Obligations [Member] | Energy Supply Procurement [Member] | Maximum [Member] | Minimum [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] | 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] | MGPSites | Curtailment Services [Member] | Public Utilities, Inventory, Fuel [Member] | Other Purchase Obligations [Member] | Energy Supply Procurement [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] | |||||||||||||||||||||||||||||||||||||||||
States | MW | MW | Claiments | Claiments | PrincipleResponsibleParties | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
OpenClaims | Customers | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
MGPSites | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commercial Commitments [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Guarantee Obligations Maximum Exposure | $9,890,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | $1,717,000,000 | [1] | $200,000,000 | $3,529,000,000 | [2] | $4,644,000,000 | [3] | ' | ' | $6,491,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $1,675,000,000 | [1] | ' | $3,529,000,000 | [2] | $1,287,000,000 | [4] | ' | $222,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $17,000,000 | [1] | $200,000,000 | $205,000,000 | [5] | $203,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | $22,000,000 | [1] | $178,000,000 | $181,000,000 | [6] | $260,000,000 | ' | ' | ' | ' | ' | ' | ' | $1,000,000 | [1] | $250,000,000 | $259,000,000 | [7] | ' | |||||||||
Commercial Commitments Footnote [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Guarantees in support of equity investment | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 211,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 211,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Estimated net exposure for commercial transaction obligations | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 500,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 300,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
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 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,500,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,400,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Spent Nuclear Fuel Obligation [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Cost of spent nuclear fuel disposal per kWh of net nuclear generation | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.001 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
NetNuclearFuelDisposalFees | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 136,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
LossContingencySettlementAbstract | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Receivable from affiliate | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,497,000,000 | 2,469,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 455,000,000 | 447,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Guarantees Related To Indemnifications [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Acquisition of interest in subsidiary | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Sale of interest in subsidiary | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 100.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Business Acquisition, Regulatory Matters [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Business Acquisition, Direct Investment With State And Local Governments Due To Settlement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Business Acquisition, Construction Cost | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 120,000,000 | ' | 95,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Business Acquisition, Development Of New Generation Cost | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 650,000,000 | ' | 600,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Business Acquisition, Expected New Generation Mwh | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 300 | ' | 285 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Business Acquisition Potential Cash Payment | 40,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Accrual For Environmental Loss Contingencies [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Accrued environmental liabilities | ' | ' | ' | ' | ' | 332,000,000 | 338,000,000 | 267,000,000 | 273,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 56,000,000 | 56,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 230,000,000 | 234,000,000 | 225,000,000 | 229,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 45,000,000 | 47,000,000 | 42,000,000 | 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 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
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 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 51,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Capital Leases, Net Investment in Direct Financing Leases [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Net investment in long-term direct financing leases | 368,000,000 | 698,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Number Of Stations Violating Clean Air Act | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Coal Rail Car Lease Proof of Claims | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 21,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Probable contingency (liability) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Midwest Generation's estimated environmental investigation and remediation costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 53,000,000 | |||||||||||||||||||||
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 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Loss Contingency Number Of Defendants | ' | ' | ' | 14 | 15 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
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] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Number of defendants in addition to BGE and Constellation Energy | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 19 | ' | ' | ' | ' | ' | |||||||||||||||||||||
Minimum estimated clean-up costs for all potentially responsible parties | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50,000,000 | ' | ' | ' | ' | ' | |||||||||||||||||||||
Maximum estimated clean-up costs for all potentially responsible parties | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,700,000 | ' | ' | ' | ' | ' | 64,000,000 | ' | ' | ' | ' | ' | |||||||||||||||||||||
Climate Change Regulation [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Minimum GHG emissions by stationary sources to qualify for regulation | 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 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 89,000,000 | 90,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Asbestos liability reserve related to open claims | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Open asbestos liability claims | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 238 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Asbestos liability reserve related to anticipated claims | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 69,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Increase (decrease) in the value of the asbestos liability reserve | ' | 25,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Asbestos reserve adjustment | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Number of claimants | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 486 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
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 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Telephone Consumer Protection Act Lawsuit [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
PossibleDefendantsNumber | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,200,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
LossContingencyDamagesSought | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,500 | 500 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Business Acquisition, Regulatory Matters [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Business Acquisition, Direct Investment With State And Local Governments Due To Settlement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Business Acquisition, Construction Cost | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 120,000,000 | ' | 95,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Business Acquisition, Development Of New Generation Cost | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 650,000,000 | ' | 600,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Business Acquisition, Expected New Generation Mwh | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 300 | ' | 285 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Business Acquisition Potential Cash Payment | 40,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Unrecorded Unconditional Purchase Obligation [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Purchase Obligations, Due within One Year | ' | ' | 150,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,073,000,000 | ' | ' | 314,000,000 | [8] | 100,000,000 | [9] | 19,000,000 | [10] | 640,000,000 | 1,036,000,000 | 90,000,000 | 120,000,000 | ' | 47,000,000 | 27,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50,000,000 | [11] | 11,000,000 | 178,000,000 | [12] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 546,000,000 | [13] | 2,000,000 | [14] | 146,000,000 | 16,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 33,000,000 | [15] | 105,000,000 | 1,000,000 | 541,000,000 | [16] | ' | ' | ' | ' | ' | ' | ||||||||||||
Purchase Obligations, Due within Two Years | ' | ' | 146,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 521,000,000 | ' | ' | 367,000,000 | [8] | 141,000,000 | [9] | 13,000,000 | [10] | 0 | 1,285,000,000 | ' | 138,000,000 | 80,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 72,000,000 | [11] | 5,000,000 | 136,000,000 | [12] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 167,000,000 | [13] | 2,000,000 | [14] | 117,000,000 | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 40,000,000 | [15] | 82,000,000 | 2,000,000 | 409,000,000 | [16] | ' | ' | ' | ' | ' | ' | ||||||||||||
Purchase Obligations, Due within Three Years | ' | ' | 58,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 382,000,000 | ' | ' | 284,000,000 | [8] | 96,000,000 | [9] | 2,000,000 | [10] | 0 | 1,039,000,000 | ' | 45,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 76,000,000 | [11] | 5,000,000 | 137,000,000 | [12] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,000,000 | [14] | 98,000,000 | 3,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 34,000,000 | [15] | 80,000,000 | 5,000,000 | 76,000,000 | [16] | ' | ' | ' | ' | ' | ' | |||||||||||||
Purchase Obligations, Due within Four Years | ' | ' | 49,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 267,000,000 | ' | ' | 223,000,000 | [8] | 42,000,000 | [9] | 2,000,000 | [10] | ' | 1,041,000,000 | ' | 41,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 77,000,000 | [11] | 5,000,000 | 140,000,000 | [12] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,000,000 | [14] | 37,000,000 | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | 2,000,000 | ' | 13,000,000 | [15] | 63,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||
Purchase Obligations, Due within Five Years | ' | ' | 36,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 122,000,000 | ' | ' | 112,000,000 | [8] | 8,000,000 | [9] | 2,000,000 | [10] | ' | 780,000,000 | ' | 30,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 83,000,000 | [11] | 5,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,000,000 | [14] | 15,000,000 | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 52,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||
Purchase Obligations, Due after Five Years | ' | ' | 108,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 450,000,000 | ' | ' | 414,000,000 | [8] | 4,000,000 | [9] | 32,000,000 | [10] | ' | 3,221,000,000 | ' | 88,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,207,000,000 | [11] | 14,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,000,000 | [14] | 66,000,000 | 6,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 258,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||||||
Purchase Obligations, Total | ' | ' | $547,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $2,815,000,000 | ' | ' | $1,714,000,000 | [8] | $391,000,000 | [9] | $70,000,000 | [10] | $640,000,000 | $8,402,000,000 | ' | $462,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $1,565,000,000 | [11] | $45,000,000 | $591,000,000 | [12] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $713,000,000 | [13] | $14,000,000 | [14] | $479,000,000 | $28,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | $120,000,000 | [15] | $640,000,000 | $10,000,000 | $1,026,000,000 | [16] | ' | ' | ' | ' | ' | ' | ||||||||||||
Unrecorded Unconditional Purchase Obligation, Additional Information [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
Percentage of ownership interest in CENG (as a percent) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50.01% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||
[1] | Non-debt letters of credit maintained to provide credit support for certain transactions as requested by third parties. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[2] | 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. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[3] | 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 $0.5 billion at March 31, 2014, which represents the total amount Exelon could be required to fund based on March 31, 2014 market prices. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[4] | 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 $0.3 billion at March 31, 2014, which represents the total amount Generation could be required to fund based on March 31, 2014 market prices. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[5] | 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. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[6] | 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. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[7] | 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. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[8] | 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 March 31, 2014, 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. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[9] | The table excludes renewable energy purchases that are contingent in nature. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[10] | Transmission rights purchases include estimated commitments for additional transmission rights that will be required to fulfill firm sales contracts. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[11] | (b)B B B B B B B B ComEd entered into 20-year contracts for renewable energy and RECs beginning in June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. The commitments represent the maximum settlements with suppliers for renewable energy and RECs under the existing contract terms. Pursuant to the ICCbs Order on DecemberB 19, 2012, ComEdbs commitments under the existing long-term contracts were reduced for the June 2013 through May 2014 procurement period. In addition, the ICCbs DecemberB 18, 2013 order approved the reduction of ComEdbs commitments under those contracts for the June 2014 through May 2015 procurement period, and the amount of the reduction was approved by the ICC in March 2014. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[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. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[13] | PECO entered into various contracts for the procurement of electric supply to serve its default service customers that expire between 2014 and 2016. PECO is permitted to recover its electric supply procurement costs from default service customers with no mark-up in accordance with its PAPUC-approved DSP Programs. See Note 4 - Regulatory Matters for additional information. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[14] | PECO is subject to requirements related to the use of alternative energy resources established by the AEPS Act. See Note 4 - 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 4 - Regulatory Matters for additional information | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[16] | BGE has entered into various contracts with curtailment services providers related to transactions in PJM's capacity market. See Note 4 - Regulatory Matters for additional information. |
Supplemental_Financial_Informa2
Supplemental Financial Information -Operations (Detail) (USD $) | 3 Months Ended | |||
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 | ||
Operating revenues [Abstract] | ' | ' | ||
Total operating revenues | $7,237 | [1] | $6,082 | [1] |
Taxes Excluding Income And Excise Taxes [Abstract] | ' | ' | ||
Total taxes other than income | 293 | 277 | ||
Equity Method Investment Summarized Financial Information Gross Profit Loss [Abstract] | ' | ' | ||
Total income (loss) in equity method investments | -19 | -9 | ||
Decommissioning-Related Activities [Abstract] | ' | ' | ||
Net realized income on decommissioning trust funds - Regulatory Agreement Units | 43 | [2] | 36 | [2] |
Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units | 25 | [2] | 14 | [2] |
Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units | 61 | 195 | ||
Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement | 13 | 64 | ||
Net unrealized income (losses) on pledged assets | 10 | 2 | ||
Regulatory offset to decommissioning trust fund-related activities | -94 | [3] | -190 | [3] |
Investment income | 1 | 3 | ||
Total decommissioning-related activities | 58 | 121 | ||
Long-term lease income | 6 | 8 | ||
Interest income related to uncertain income tax positions | 10 | 25 | ||
AFUDC - equity | 6 | 6 | ||
Other Income | 22 | 9 | ||
Other, net | 103 | 172 | ||
Exelon Generation Co L L C [Member] | ' | ' | ||
Operating revenues [Abstract] | ' | ' | ||
Total operating revenues | 4,390 | 3,533 | ||
Taxes Excluding Income And Excise Taxes [Abstract] | ' | ' | ||
Total taxes other than income | 105 | 93 | ||
Equity Method Investment Summarized Financial Information Gross Profit Loss [Abstract] | ' | ' | ||
Total income (loss) in equity method investments | -19 | -9 | ||
Decommissioning-Related Activities [Abstract] | ' | ' | ||
Net realized income on decommissioning trust funds - Regulatory Agreement Units | 43 | [2] | 36 | [2] |
Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units | 25 | [2] | 14 | [2] |
Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units | 61 | 195 | ||
Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement | 13 | 64 | ||
Net unrealized income (losses) on pledged assets | 10 | 2 | ||
Regulatory offset to decommissioning trust fund-related activities | -94 | [3] | -190 | [3] |
Investment income | 1 | -2 | ||
Total decommissioning-related activities | 58 | 121 | ||
Interest income related to uncertain income tax positions | 14 | 5 | ||
Other Income | 17 | 4 | ||
Other, net | 90 | 128 | ||
Commonwealth Edison Co [Member] | ' | ' | ||
Operating revenues [Abstract] | ' | ' | ||
Total operating revenues | 1,134 | 1,160 | ||
Taxes Excluding Income And Excise Taxes [Abstract] | ' | ' | ||
Total taxes other than income | 77 | 74 | ||
Decommissioning-Related Activities [Abstract] | ' | ' | ||
Investment income | 0 | 0 | ||
Interest income related to uncertain income tax positions | 0 | 0 | ||
AFUDC - equity | 3 | 3 | ||
Other Income | 2 | 2 | ||
Other, net | 5 | 5 | ||
PECO Energy Co [Member] | ' | ' | ||
Operating revenues [Abstract] | ' | ' | ||
Total operating revenues | 993 | 895 | ||
Taxes Excluding Income And Excise Taxes [Abstract] | ' | ' | ||
Total taxes other than income | 42 | 41 | ||
Decommissioning-Related Activities [Abstract] | ' | ' | ||
Investment income | 0 | 0 | ||
Interest income related to uncertain income tax positions | 0 | 0 | ||
AFUDC - equity | 1 | 1 | ||
Other Income | 1 | 2 | ||
Other, net | 2 | 3 | ||
Baltimore Gas and Electric Company [Member] | ' | ' | ||
Operating revenues [Abstract] | ' | ' | ||
Total operating revenues | 1,054 | 880 | ||
Taxes Excluding Income And Excise Taxes [Abstract] | ' | ' | ||
Total taxes other than income | 60 | 55 | ||
Decommissioning-Related Activities [Abstract] | ' | ' | ||
Investment income | 2 | [4] | 2 | [4] |
Interest income related to uncertain income tax positions | 0 | 0 | ||
AFUDC - equity | 3 | 2 | ||
Other Income | -1 | 1 | ||
Other, net | $4 | $5 | ||
[1] | For the ##D<curmonth> months ended ##D<cyperiod> and ##D<pyfiscal>, utility taxes of $##D<gcytdutiltax> million and $##D<gpytdutiltax> million, respectively, are included in revenues and expenses for Generation. For the ##D<curmonth> months ended ##D<cyperiod> and ##D<pyfiscal>, utility taxes of $##D<ccytdutiltax> million and $##D<cpytdutiltax> million, respectively, are included in revenues and expenses for ComEd. For the ##D<curmonth> months ended ##D<cyperiod> and ##D<pyfiscal>, utility taxes of $##D<pcytdutiltax> million and $##D<ppytdutiltax> million, respectively, are included in revenues and expenses for PECO. For the ##D<curmonth> months ended ##D<cyperiod> and period of March 12, 2012 through ##D<pyperiod>, utility taxes of $##D<bcytdutiltax> million and $##D<bpytdutiltax> million, respectively, are included in revenues and expenses for BGE. | |||
[2] | Includes investment income and realized gains and losses on sales of investments of the trust funds. | |||
[3] | Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of net income taxes related to all NDT fund activity for those units. See Note 15 b Asset Retirement Obligations of the Exelon 2013 Form 10-K for additional information regarding the accounting for nuclear decommissioning. | |||
[4] | Relates to the cash return on BGEbs rate stabilization deferral. See Note 4 - Regulatory Matters for additional information regarding the rate stabilization deferral. |
Supplemental_Financial_Informa3
Supplemental Financial Information - Cash Flow (Details) (USD $) | 3 Months Ended | |||
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 | ||
Depreciation, Amortization and Accretion [Abstract] | ' | ' | ||
Property, plant and equipment | $481 | $471 | ||
Regulatory assets | 72 | 61 | ||
Amortization of intangible assets, net | 11 | 11 | ||
Amortization of energy contract assets and liabilities | 42 | [1] | 176 | [1] |
Nuclear fuel | 234 | [1] | 230 | [1] |
Asset retirement obligation accretion | 68 | [2] | 68 | [2] |
Total depreciation, amortization and accretion | 908 | 1,017 | ||
Other Non-Cash Operating Activities [Abstract] | ' | ' | ||
Pension and non-pension postretirement benefits costs | 173 | 205 | ||
Provision for uncollectible accounts | 35 | 45 | ||
Provision for Obsolete Inventory | 2 | ' | ||
Stock-based compensation costs | 46 | 39 | ||
Other Decommissioning Related Activity | -35 | [3] | -64 | [3] |
Energy-related options | 31 | [4] | 21 | [4] |
Amortization of regulatory asset related to debt costs | 3 | 4 | ||
Amortization of rate stabilization deferral | 20 | 30 | ||
Amortization of debt fair value adjustment | -12 | -9 | ||
Discrete impacts from EIMA | -4 | -49 | [5] | |
Merger related commitments | ' | -6 | ||
Gain (loss) on equity method investments | 19 | 9 | ||
Amortization of debt costs | 5 | 5 | ||
Other | -11 | 1 | ||
Total other noncash operating activities | 272 | 231 | ||
Changes In Other Assets and Liabilities [Abstract] | ' | ' | ||
Under/over-recovered energy and transmission costs | -15 | 29 | ||
Other regulatory assets and liabilities | 4 | -91 | ||
Other current assets and liabilities | -209 | -169 | ||
Other noncurrent assets and liabilities | -50 | 282 | ||
Total changes in other assets and liabilities | -278 | 233 | ||
Cash Flow Noncash Investing And Financing Activities Disclosure [Abstract] | ' | ' | ||
Consolidated VIE dividend to non-controlling interest | -2 | 63 | ||
Total noncash investing and financing activities | 0 | 63 | ||
DOE Smart Grid Investment Grant [Abstract] | ' | ' | ||
Amount included in capital expenditures | 2 | 21 | ||
Smart Grid Grant Reimbursements | 2 | 32 | ||
Exelon Generation Co L L C [Member] | ' | ' | ||
Depreciation, Amortization and Accretion [Abstract] | ' | ' | ||
Property, plant and equipment | 200 | 203 | ||
Amortization of intangible assets, net | 11 | 11 | ||
Amortization of energy contract assets and liabilities | 44 | [1] | 176 | [1] |
Nuclear fuel | 234 | [1] | 230 | [1] |
Asset retirement obligation accretion | 68 | [2] | 68 | [2] |
Total depreciation, amortization and accretion | 557 | 688 | ||
Other Non-Cash Operating Activities [Abstract] | ' | ' | ||
Pension and non-pension postretirement benefits costs | 75 | 87 | ||
Provision for uncollectible accounts | 1 | 7 | ||
Provision for Obsolete Inventory | 2 | ' | ||
Stock-based compensation costs | 0 | 4 | ||
Other Decommissioning Related Activity | -35 | [3] | -64 | [3] |
Energy-related options | 31 | [4] | 21 | [4] |
Amortization of debt fair value adjustment | -5 | -9 | ||
Merger related commitments | ' | 0 | ||
Gain (loss) on equity method investments | 19 | 9 | ||
Amortization of debt costs | 3 | 3 | ||
Other | -6 | 8 | ||
Total other noncash operating activities | 85 | 66 | ||
Changes In Other Assets and Liabilities [Abstract] | ' | ' | ||
Other current assets and liabilities | -80 | -131 | ||
Other noncurrent assets and liabilities | -23 | -28 | ||
Total changes in other assets and liabilities | -103 | -159 | ||
Cash Flow Noncash Investing And Financing Activities Disclosure [Abstract] | ' | ' | ||
Consolidated VIE dividend to non-controlling interest | ' | 63 | ||
Total noncash investing and financing activities | 0 | 63 | ||
Commonwealth Edison Co [Member] | ' | ' | ||
Depreciation, Amortization and Accretion [Abstract] | ' | ' | ||
Property, plant and equipment | 143 | 137 | ||
Regulatory assets | 30 | 30 | ||
Total depreciation, amortization and accretion | 173 | 167 | ||
Other Non-Cash Operating Activities [Abstract] | ' | ' | ||
Pension and non-pension postretirement benefits costs | 56 | 77 | ||
Provision for uncollectible accounts | -11 | 9 | ||
Stock-based compensation costs | 0 | 1 | ||
Amortization of regulatory asset related to debt costs | 2 | 3 | ||
Discrete impacts from EIMA | -4 | -49 | [5] | |
Amortization of debt costs | -5 | 1 | ||
Other | -2 | 0 | ||
Total other noncash operating activities | 36 | 42 | ||
Changes In Other Assets and Liabilities [Abstract] | ' | ' | ||
Under/over-recovered energy and transmission costs | 4 | -18 | ||
Other regulatory assets and liabilities | 10 | 14 | ||
Other current assets and liabilities | -29 | 17 | ||
Other noncurrent assets and liabilities | 11 | 263 | ||
Total changes in other assets and liabilities | -24 | 248 | ||
Cash Flow Noncash Investing And Financing Activities Disclosure [Abstract] | ' | ' | ||
Allocation Of Tax Benefit From Parent | 2 | ' | ||
Indemnification of like-kind exchange position | -38 | 0 | ||
Total noncash investing and financing activities | -2 | 172 | ||
Commonwealth Edison Co [Member] | Indemnification Agreement [Member] | ' | ' | ||
Cash Flow Noncash Investing And Financing Activities Disclosure [Abstract] | ' | ' | ||
Indemnification of like-kind exchange position | 2 | -172 | ||
PECO Energy Co [Member] | ' | ' | ||
Depreciation, Amortization and Accretion [Abstract] | ' | ' | ||
Property, plant and equipment | 56 | 55 | ||
Regulatory assets | 2 | 2 | ||
Total depreciation, amortization and accretion | 58 | 57 | ||
Other Non-Cash Operating Activities [Abstract] | ' | ' | ||
Pension and non-pension postretirement benefits costs | 12 | 11 | ||
Provision for uncollectible accounts | 35 | 25 | ||
Stock-based compensation costs | 0 | 1 | ||
Amortization of regulatory asset related to debt costs | 1 | 1 | ||
Amortization of debt costs | 1 | 1 | ||
Other | 0 | 0 | ||
Total other noncash operating activities | 49 | 39 | ||
Changes In Other Assets and Liabilities [Abstract] | ' | ' | ||
Under/over-recovered energy and transmission costs | -17 | 22 | ||
Other regulatory assets and liabilities | 3 | -13 | ||
Other current assets and liabilities | -105 | -75 | ||
Other noncurrent assets and liabilities | -2 | 2 | ||
Total changes in other assets and liabilities | -127 | -38 | ||
DOE Smart Grid Investment Grant [Abstract] | ' | ' | ||
Amount included in capital expenditures | 2 | 6 | ||
Smart Grid Grant Reimbursements | 2 | 12 | ||
Baltimore Gas and Electric Company [Member] | ' | ' | ||
Depreciation, Amortization and Accretion [Abstract] | ' | ' | ||
Property, plant and equipment | 70 | 64 | ||
Regulatory assets | 38 | 29 | ||
Total depreciation, amortization and accretion | 108 | 93 | ||
Other Non-Cash Operating Activities [Abstract] | ' | ' | ||
Pension and non-pension postretirement benefits costs | 16 | 14 | ||
Provision for uncollectible accounts | 11 | 4 | ||
Stock-based compensation costs | 0 | 1 | ||
Amortization of regulatory asset related to debt costs | 0 | 0 | ||
Amortization of rate stabilization deferral | 20 | 30 | ||
Merger related commitments | ' | -6 | ||
Amortization of debt costs | 0 | ' | ||
Other | -4 | -1 | ||
Total other noncash operating activities | 43 | 42 | ||
Changes In Other Assets and Liabilities [Abstract] | ' | ' | ||
Under/over-recovered energy and transmission costs | 23 | 16 | ||
Other regulatory assets and liabilities | -6 | 53 | ||
Other current assets and liabilities | 18 | 73 | ||
Other noncurrent assets and liabilities | -3 | -2 | ||
Total changes in other assets and liabilities | 44 | 34 | ||
Cash Flow Noncash Investing And Financing Activities Disclosure [Abstract] | ' | ' | ||
Indemnification of like-kind exchange position | 0 | 0 | ||
DOE Smart Grid Investment Grant [Abstract] | ' | ' | ||
Amount included in capital expenditures | ' | 15 | ||
Smart Grid Grant Reimbursements | ' | $20 | ||
[1] | Included in Operating revenues or 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 activity for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 15 of the Exelon 2013 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 4 - Regulatory Matters for more information. |
Supplemental_Financial_Informa4
Supplemental Financial Information - Balance Sheet (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||
Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2010 | Dec. 31, 2013 | Dec. 31, 2012 | |||||
Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract] | ' | ' | ' | ' | ' | ||||
Equity Method Investments | $1,910,000,000 | ' | ' | $1,925,000,000 | ' | ||||
Supplemental Financial Information Textuals [Abstract] | ' | ' | ' | ' | ' | ||||
Payment to IRS | ' | ' | 302,000,000 | ' | ' | ||||
Capital Leases, Net Investment in Direct Financing Leases [Abstract] | ' | ' | ' | ' | ' | ||||
Estimated residual value of leased assets | 731,000,000 | ' | ' | 1,465,000,000 | ' | ||||
Less: unearned income | -363,000,000 | ' | ' | -767,000,000 | ' | ||||
Net investment in long-term leases | 368,000,000 | ' | ' | 698,000,000 | ' | ||||
CapitalLeaseNetInvestmentInDirectFinancingLeasesPrepaymentsReceived | 1,200,000,000 | ' | ' | ' | ' | ||||
Utilities Operating Expense Maintenance And Operations [Abstract] | ' | ' | ' | ' | ' | ||||
Operating and maintenance | 1,858,000,000 | 1,764,000,000 | ' | ' | ' | ||||
Accrued Liabilities Current [Abstract] | ' | ' | ' | ' | ' | ||||
Taxes accrued | 285,000,000 | ' | ' | ' | ' | ||||
Total accrued expenses | 1,364,000,000 | ' | ' | 1,633,000,000 | ' | ||||
Property, Plant And Equipment [Abstract] | ' | ' | ' | ' | ' | ||||
Accumulated depreciation | 14,066,000,000 | [1] | ' | ' | 13,713,000,000 | [2] | ' | ||
Accumulated amortization of nuclear fuel | 2,425,000,000 | ' | ' | 2,371,000,000 | ' | ||||
Accounts receivable, net | ' | ' | ' | ' | ' | ||||
Allowance for uncollectible accounts | 306,000,000 | ' | ' | 272,000,000 | ' | ||||
Accumulated Other Comprehensive Income (Loss) [Abstract] | ' | ' | ' | ' | ' | ||||
Accumulated other comprehensive income (loss), net | -2,036,000,000 | [3] | -2,673,000,000 | [3] | ' | -2,040,000,000 | [3] | -2,767,000,000 | [3] |
Capital Leases, Net Investment in Direct Financing Leases, Initial Direct Costs | 1,600,000,000 | ' | ' | ' | ' | ||||
CPS Board San Antonio, Texas | EquipmentLeasedToOtherPartyMember | ' | ' | ' | ' | ' | ||||
Utilities Operating Expense Maintenance And Operations [Abstract] | ' | ' | ' | ' | ' | ||||
Cash Proceeds from Direct Finance Lease Contract Termination | 335,000,000 | 0 | ' | ' | ' | ||||
Exelon Generation Co L L C [Member] | ' | ' | ' | ' | ' | ||||
Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract] | ' | ' | ' | ' | ' | ||||
Equity Method Investments | 1,910,000,000 | ' | ' | 1,925,000,000 | ' | ||||
Utilities Operating Expense Maintenance And Operations [Abstract] | ' | ' | ' | ' | ' | ||||
Operating and maintenance | 938,000,000 | 965,000,000 | ' | ' | ' | ||||
Accrued Liabilities Current [Abstract] | ' | ' | ' | ' | ' | ||||
Total accrued expenses | 831,000,000 | ' | ' | 976,000,000 | ' | ||||
Property, Plant And Equipment [Abstract] | ' | ' | ' | ' | ' | ||||
Accumulated depreciation | 7,245,000,000 | [1] | ' | ' | 7,034,000,000 | [2] | ' | ||
Accumulated amortization of nuclear fuel | 2,425,000,000 | ' | ' | 2,371,000,000 | ' | ||||
Accounts receivable, net | ' | ' | ' | ' | ' | ||||
Allowance for uncollectible accounts | 46,000,000 | ' | ' | 57,000,000 | ' | ||||
Accumulated Other Comprehensive Income (Loss) [Abstract] | ' | ' | ' | ' | ' | ||||
Accumulated other comprehensive income (loss), net | 193,000,000 | [3] | 409,000,000 | [3] | ' | 214,000,000 | [3] | 513,000,000 | [3] |
Exelon Generation Co L L C [Member] | CPS Board San Antonio, Texas | EquipmentLeasedToOtherPartyMember | ' | ' | ' | ' | ' | ||||
Utilities Operating Expense Maintenance And Operations [Abstract] | ' | ' | ' | ' | ' | ||||
Operating and maintenance | 1,000,000 | ' | ' | ' | ' | ||||
Cash Proceeds from Direct Finance Lease Contract Termination | 335,000,000 | ' | ' | ' | ' | ||||
Capital Leases Written Off | 336,000,000 | ' | ' | ' | ' | ||||
Commonwealth Edison Co [Member] | ' | ' | ' | ' | ' | ||||
Utilities Operating Expense Maintenance And Operations [Abstract] | ' | ' | ' | ' | ' | ||||
Operating and maintenance | 287,000,000 | 292,000,000 | ' | ' | ' | ||||
Accrued Liabilities Current [Abstract] | ' | ' | ' | ' | ' | ||||
Total accrued expenses | 214,000,000 | ' | ' | 307,000,000 | ' | ||||
Property, Plant And Equipment [Abstract] | ' | ' | ' | ' | ' | ||||
Accumulated depreciation | 3,247,000,000 | ' | ' | 3,184,000,000 | ' | ||||
Accounts receivable, net | ' | ' | ' | ' | ' | ||||
Allowance for uncollectible accounts | 76,000,000 | ' | ' | 62,000,000 | ' | ||||
Accumulated Other Comprehensive Income (Loss) [Abstract] | ' | ' | ' | ' | ' | ||||
Accumulated other comprehensive income (loss), net | 0 | ' | ' | 0 | ' | ||||
PECO Energy Co [Member] | ' | ' | ' | ' | ' | ||||
Utilities Operating Expense Maintenance And Operations [Abstract] | ' | ' | ' | ' | ' | ||||
Operating and maintenance | 256,000,000 | 164,000,000 | ' | ' | ' | ||||
Accrued Liabilities Current [Abstract] | ' | ' | ' | ' | ' | ||||
Total accrued expenses | 137,000,000 | ' | ' | 106,000,000 | ' | ||||
Property, Plant And Equipment [Abstract] | ' | ' | ' | ' | ' | ||||
Accumulated depreciation | 2,958,000,000 | ' | ' | 2,935,000,000 | ' | ||||
Accounts receivable, net | ' | ' | ' | ' | ' | ||||
Allowance for uncollectible accounts | 140,000,000 | ' | ' | 107,000,000 | ' | ||||
Installment plan receivables | 18,000,000 | ' | ' | 19,000,000 | ' | ||||
Installment plan receivables uncollectible accounts reserve | -15,000,000 | ' | ' | -18,000,000 | ' | ||||
Accumulated Other Comprehensive Income (Loss) [Abstract] | ' | ' | ' | ' | ' | ||||
Accumulated other comprehensive income (loss), net | 1,000,000 | [3] | 1,000,000 | [3] | ' | 1,000,000 | [3] | 1,000,000 | [3] |
PECO Energy Co [Member] | Low To Medium Risk [Member] | ' | ' | ' | ' | ' | ||||
Accounts receivable, net | ' | ' | ' | ' | ' | ||||
Installment plan receivables uncollectible accounts reserve | -1,000,000 | ' | ' | -1,000,000 | ' | ||||
PECO Energy Co [Member] | Medium Risk [Member] | ' | ' | ' | ' | ' | ||||
Accounts receivable, net | ' | ' | ' | ' | ' | ||||
Installment plan receivables uncollectible accounts reserve | -4,000,000 | ' | ' | -4,000,000 | ' | ||||
PECO Energy Co [Member] | High Risk [Member] | ' | ' | ' | ' | ' | ||||
Accounts receivable, net | ' | ' | ' | ' | ' | ||||
Installment plan receivables uncollectible accounts reserve | -10,000,000 | ' | ' | -13,000,000 | ' | ||||
Baltimore Gas and Electric Company [Member] | ' | ' | ' | ' | ' | ||||
Utilities Operating Expense Maintenance And Operations [Abstract] | ' | ' | ' | ' | ' | ||||
Operating and maintenance | 163,000,000 | 124,000,000 | ' | ' | ' | ||||
Accrued Liabilities Current [Abstract] | ' | ' | ' | ' | ' | ||||
Total accrued expenses | 111,000,000 | ' | ' | 111,000,000 | ' | ||||
Property, Plant And Equipment [Abstract] | ' | ' | ' | ' | ' | ||||
Accumulated depreciation | 2,741,000,000 | ' | ' | 2,702,000,000 | ' | ||||
Accounts receivable, net | ' | ' | ' | ' | ' | ||||
Allowance for uncollectible accounts | $44,000,000 | ' | ' | $46,000,000 | ' | ||||
[1] | Includes accumulated amortization of nuclear fuel in the reactor core of $2,425 million. | ||||||||
[2] | Includes accumulated amortization of nuclear fuel in the reactor core of $2,371 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 | ||||
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | ||
ReportableSegments | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | $7,237 | [1] | $6,082 | [1] | ' |
Income taxes | -54 | 56 | ' | ||
Net income (loss) | 93 | 1 | ' | ||
Total assets | 79,468 | 79,924 | 79,924 | ||
Segment Reporting Additional Information [Abstract] | ' | ' | ' | ||
Number of reportable segments | 9 | ' | ' | ||
Unrealized Gain (Loss) on Derivatives | -730 | -388 | ' | ||
Intersegment Eliminations [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Operating revenues from affiliates | 1 | 0 | ' | ||
Exelon Generation Co L L C [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | ' | 3,533 | ' | ||
Segment Reporting Additional Information [Abstract] | ' | ' | ' | ||
Number of reportable segments | 6 | ' | ' | ||
Exelon Generation Co L L C [Member] | Operating Segments [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | 4,390 | [1],[2] | ' | ' | |
Operating revenues from affiliates | 316 | 381 | ' | ||
Net income (loss) | -185 | [2] | -17 | [2] | ' |
Total assets | 41,080 | 41,232 | ' | ||
Segment Reporting Additional Information [Abstract] | ' | ' | ' | ||
Utility taxes | 24 | 21 | ' | ||
Exelon Generation Co L L C [Member] | Baltimore Gas And Electric Company Affiliate [Member] | Operating Segments [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | 120 | ' | ' | ||
Exelon Generation Co L L C [Member] | Commonwealth Edison Co Affiliate [Member] | Operating Segments [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | 108 | 145 | ' | ||
Segment Reporting Additional Information [Abstract] | ' | ' | ' | ||
Unrealized Gain (Loss) on Derivatives | 0 | -17 | ' | ||
Exelon Generation Co L L C [Member] | PECO Energy Co Affiliate [Member] | Operating Segments [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | 88 | 141 | ' | ||
Generation Mid Atlantic [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | 1,418 | 1,323 | ' | ||
Revenue net of purchased power and fuel expense, Total | 695 | 844 | ' | ||
Generation Mid Atlantic [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | -23 | -8 | ' | ||
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity | -89 | -8 | ' | ||
Generation Mid Atlantic [Member] | Operating Segments [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | 1,441 | [3],[4] | 1,331 | [3],[4] | ' |
Revenue net of purchased power and fuel expense from external customers | 784 | [5] | 852 | [5] | ' |
Generation Mid Atlantic [Member] | Baltimore Gas And Electric Company Affiliate [Member] | Operating Segments [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | ' | 113 | ' | ||
Generation Midwest [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | 1,270 | 1,188 | ' | ||
Revenue net of purchased power and fuel expense, Total | 556 | 717 | ' | ||
Generation Midwest [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | 12 | 7 | ' | ||
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity | 26 | 7 | ' | ||
Generation Midwest [Member] | Operating Segments [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | 1,258 | [3],[4] | 1,181 | [3],[4] | ' |
Revenue net of purchased power and fuel expense from external customers | 530 | [5] | 710 | [5] | ' |
Generation New England [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | 549 | 403 | ' | ||
Revenue net of purchased power and fuel expense, Total | 136 | 30 | ' | ||
Generation New England [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | 4 | 12 | ' | ||
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity | -18 | 12 | ' | ||
Generation New England [Member] | Operating Segments [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | 545 | [3],[4] | 391 | [3],[4] | ' |
Revenue net of purchased power and fuel expense from external customers | 154 | [5] | 18 | [5] | ' |
Generation New York [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | 187 | 169 | ' | ||
Revenue net of purchased power and fuel expense, Total | -21 | -22 | ' | ||
Generation New York [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | -3 | -6 | ' | ||
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity | 8 | -6 | ' | ||
Generation New York [Member] | Operating Segments [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | 190 | [3],[4] | 175 | [3],[4] | ' |
Revenue net of purchased power and fuel expense from external customers | -29 | [5] | -16 | [5] | ' |
Generation ERCOT [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | 243 | 293 | ' | ||
Revenue net of purchased power and fuel expense, Total | 83 | 101 | ' | ||
Generation ERCOT [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 | -72 | ' | ' | ||
Generation ERCOT [Member] | Operating Segments [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | 243 | [4] | 293 | [3],[4] | ' |
Revenue net of purchased power and fuel expense from external customers | 155 | [5] | 112 | [5] | ' |
Generation Other Regions [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | 341 | [6],[7] | 225 | [6],[7] | ' |
Revenue net of purchased power and fuel expense, Total | 105 | [6],[8] | 45 | [6],[8] | ' |
Generation Other Regions [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | 7 | [6],[7] | 42 | [6],[7] | ' |
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity | -45 | [6],[8] | 35 | [6],[8] | ' |
Generation Other Regions [Member] | Operating Segments [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | 334 | [3],[4],[6],[7] | 183 | [3],[4],[6],[7] | ' |
Revenue net of purchased power and fuel expense from external customers | 150 | [5],[6],[8] | 10 | [5],[6],[8] | ' |
Generation Reportable Segments Total [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | 4,008 | 3,601 | ' | ||
Revenue net of purchased power and fuel expense, Total | 1,554 | 1,715 | ' | ||
Generation Reportable Segments Total [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | -3 | 47 | ' | ||
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity | -190 | 29 | ' | ||
Generation Reportable Segments Total [Member] | Operating Segments [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | 4,011 | [3],[4] | 3,554 | [3],[4] | ' |
Revenue net of purchased power and fuel expense from external customers | 1,744 | [5] | 1,686 | [5] | ' |
Generation Total Consolidated Group [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | 4,390 | 3,533 | ' | ||
Revenue net of purchased power and fuel expense from external customers | 1,033 | [5] | 1,364 | [5] | ' |
Revenue net of purchased power and fuel expense, Total | 1,033 | 1,364 | ' | ||
Generation Total Consolidated Group [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | ' | 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 | 4,390 | [3],[4] | 3,533 | [3],[4] | ' |
Generation All Other Segments [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | 382 | [10],[9] | -68 | [10],[9] | ' |
Revenue net of purchased power and fuel expense, Total | ' | -351 | [11],[12] | ' | |
Generation All Other Segments [Member] | Other Segments [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | 379 | [10],[3],[4],[9] | -21 | [10],[3],[4],[9] | ' |
Revenue net of purchased power and fuel expense from external customers | -711 | [11],[12],[5] | -322 | [11],[12],[5] | ' |
Segment Reporting Additional Information [Abstract] | ' | ' | ' | ||
Amortization of intangible assets related to commodity contracts | 125 | 404 | ' | ||
Amortization Of Intangible Assets Related To Commodity Contracts For Revenue Net Purchased Power And Fuel | 44 | 257 | ' | ||
Generation All Other Segments [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | 3 | [10] | -47 | [10],[9] | ' |
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity | 190 | [11],[12] | -29 | [11],[12] | ' |
Commonwealth Edison Co [Member] | Operating Segments [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | 1,134 | [1] | 1,160 | [1] | ' |
Operating revenues from affiliates | 1 | 1 | ' | ||
Net income (loss) | 98 | -81 | ' | ||
Total assets | 24,294 | 24,118 | ' | ||
Segment Reporting Additional Information [Abstract] | ' | ' | ' | ||
Utility taxes | 63 | 60 | ' | ||
PECO Energy Co [Member] | Operating Segments [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | 993 | [1] | 895 | [1] | ' |
Operating revenues from affiliates | 1 | 0 | ' | ||
Net income (loss) | 89 | 122 | ' | ||
Total assets | 9,766 | 9,617 | ' | ||
Segment Reporting Additional Information [Abstract] | ' | ' | ' | ||
Utility taxes | 35 | 34 | ' | ||
Baltimore Gas and Electric Company [Member] | Operating Segments [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | 1,054 | [1],[13] | 880 | [1],[13] | ' |
Operating revenues from affiliates | 16 | 4 | ' | ||
Net income (loss) | 88 | [13] | 80 | [13] | ' |
Total assets | 7,958 | 7,861 | ' | ||
Segment Reporting Additional Information [Abstract] | ' | ' | ' | ||
Utility taxes | 20 | 22 | ' | ||
Corporate and Other [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenue net of purchased power and fuel expense, Total | -521 | [11] | ' | ' | |
Corporate and Other [Member] | Other Segments [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | 290 | [1],[14] | 318 | [1],[14] | ' |
Operating revenues from affiliates | 290 | 318 | ' | ||
Net income (loss) | 4 | [14] | -103 | [14] | ' |
Total assets | 8,146 | 8,317 | ' | ||
Segment Elimination [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ||
Segment Reporting Information [Line Items] | ' | ' | ' | ||
Revenues | -624 | [15] | -704 | [15] | ' |
Operating revenues from affiliates | -623 | -704 | ' | ||
Net income (loss) | -1 | 0 | ' | ||
Total assets | ($11,776) | ($11,221) | ' | ||
[1] | For the ##D<curmonth> months ended ##D<cyperiod> and ##D<pyfiscal>, utility taxes of $##D<gcytdutiltax> million and $##D<gpytdutiltax> million, respectively, are included in revenues and expenses for Generation. For the ##D<curmonth> months ended ##D<cyperiod> and ##D<pyfiscal>, utility taxes of $##D<ccytdutiltax> million and $##D<cpytdutiltax> million, respectively, are included in revenues and expenses for ComEd. For the ##D<curmonth> months ended ##D<cyperiod> and ##D<pyfiscal>, utility taxes of $##D<pcytdutiltax> million and $##D<ppytdutiltax> million, respectively, are included in revenues and expenses for PECO. For the ##D<curmonth> months ended ##D<cyperiod> and period of March 12, 2012 through ##D<pyperiod>, utility taxes of $##D<bcytdutiltax> million and $##D<bpytdutiltax> million, respectively, are included in revenues and expenses for BGE. | ||||
[2] | 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 ##D<curmonth> months ended ##D<cyperiod> include revenue from sales to PECO of $##D<gcyytdrevPECO> million and sales to BGE of $##D<gcyytdrevBGE> million in the Mid-Atlantic region, and sales to ComEd of $##D<gcyytdrevComEd> million in the Midwest region, net of $##D<gcyytdrevComEdSwap> million related to the unrealized mark-to-market losses related to the ComEd swap, which eliminate upon consolidation. For the ##D<curmonth> months ended ##D<pyperiod> intersegment revenues for Generation include revenue from sales to PECO of $##D<gpyytdrevPECO> million in the Mid-Atlantic region and sales to BGE of $##D<gpyytdrevBGE> million in the Mid-Atlantic region, and sales to ComEd of $##D<gpyytdrevComEd> million in the Midwest region, net of $##D<gpyytdrevComEdSwap> million related to the unrealized ma... | ||||
[3] | all wholesale and retail electric sales from third parties and affiliated sales to ComEd, PECO and BGE. | ||||
[4] | Includes all electric sales to third parties and affiliated sales to ComEd, PECO and BGE. | ||||
[5] | Includes purchases and sales from third parties and affiliated sales to ComEd, PECO and BGE. | ||||
[6] | Other regions include the South, West and Canada, which are not considered individually significant. | ||||
[7] | Other regions include the South, West and Canada, which are not considered individually significant. | ||||
[8] | Other regions includes the South, West and Canada, which are not considered individually significant. | ||||
[9] | 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 $##D<gpurchacctg> million and $##D<gpypurchacctgytd> million, for the ##D<curmonth> months ended ##D<cyperiod> and 2012, respectively. | ||||
[10] | 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 $93 million and $174 million, for the three months ended March 31, 2014 and 2013, respectively, and elimination of intersegment revenues. | ||||
[11] | 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 $42 million and $174 million for the three months ended March 31, 2014 and 2013, respectively | ||||
[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 at the merger date of $386 million and $793 million, for the ##D<curmonth> months ended ##D<cyperiod> and ##D<pyfiscal>, respectively. | ||||
[13] | Amounts represent activity recorded at BGE from March 12, 2012, the closing date of the merger, through ##D<pyperiod>. | ||||
[14] | Other primarily includes Exelon?s corporate operations, shared service entities and other financing and investment activities | ||||
[15] | 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 |
Related_Party_Transactions_Det
Related Party Transactions (Details) (USD $) | 3 Months Ended | ||||
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | ||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | ||
Purchased power from affiliate | $334 | $318 | ' | ||
Total interest expense to affiliates, net | 10 | 6 | ' | ||
Total income (loss) in equity method investments | -19 | -9 | ' | ||
Dividends paid on common stock | -266 | -450 | ' | ||
Related Party Balance Sheet [Abstract] | ' | ' | ' | ||
Investments in affiliates | 22 | ' | 22 | ||
Total payables to affiliates (current) | 94 | ' | 116 | ||
Equity Method Investment Summarized Financial Information[Abstract] | ' | ' | ' | ||
Amortization of energy contract assets and liabilities | 42 | [1] | 176 | [1] | ' |
Constellation Energy Nuclear Group [Member] | ' | ' | ' | ||
Schedule of Equity Method Investments [Line Items] | ' | ' | ' | ||
CENG | 93 | 53 | ' | ||
Amortization of basis difference in CENG | -88 | -131 | ' | ||
Total equity investment earnings (losses) - CENG | 5 | -78 | ' | ||
Exelon Generation Co L L C [Member] | ' | ' | ' | ||
Schedule of Equity Method Investments [Line Items] | ' | ' | ' | ||
Percentage of ownership interest in CENG (as a percent) | 50.01% | ' | ' | ||
Basis difference in investment in CENG | 204 | ' | ' | ||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | ||
Operating revenues from affiliates | 334 | 392 | ' | ||
Operating and maintenance from affiliate | 149 | 147 | ' | ||
Total interest expense to affiliates, net | 12 | 17 | ' | ||
Total income (loss) in equity method investments | -19 | -9 | ' | ||
Cash distribution paid to member | 30 | 211 | ' | ||
Contributions from member | 0 | 0 | ' | ||
Related Party Balance Sheet [Abstract] | ' | ' | ' | ||
Mark-to-market derivative assets with affiliates | 0 | ' | 0 | ||
Total receivables from affiliates (current) | 122 | ' | 108 | ||
Mark-to-market derivative assets with affiliate (noncurrent assets) | 0 | ' | 0 | ||
Investments in affiliates | 0 | ' | 0 | ||
Total payables to affiliates (current) | 186 | ' | 181 | ||
Total payables to affiliates (noncurrent) | 2,773 | ' | 2,740 | ||
Equity Method Investment Summarized Financial Information[Abstract] | ' | ' | ' | ||
Purchase of nuclear output by EDF (as a percent) | 49.99% | ' | ' | ||
Amortization of energy contract assets and liabilities | 44 | [1] | 176 | [1] | ' |
Exelon Generation Co L L C [Member] | Minimum [Member] | ' | ' | ' | ||
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% | ' | ' | ||
Exelon Generation Co L L C [Member] | Constellation Energy Nuclear Group [Member] | ' | ' | ' | ||
Schedule of Equity Method Investments [Line Items] | ' | ' | ' | ||
CENG | -2 | 15 | ' | ||
Amortization of basis difference in CENG | -17 | -27 | ' | ||
Total equity investment earnings (losses) - CENG | -19 | -12 | ' | ||
Commonwealth Edison Co [Member] | ' | ' | ' | ||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | ||
Operating revenues from affiliates | 1 | 1 | ' | ||
Purchased power from affiliate | 108 | 145 | ' | ||
Operating and maintenance from affiliate | 39 | 36 | ' | ||
Total interest expense to affiliates, net | 3 | 3 | ' | ||
Dividends paid on common stock | -76 | -55 | ' | ||
Contributions from parent | 38 | 0 | ' | ||
Related Party Balance Sheet [Abstract] | ' | ' | ' | ||
Total receivable from affiliates (noncurrent) | 2,497 | ' | 2,469 | ||
Investments in affiliates | 6 | ' | 6 | ||
Total payables to affiliates (current) | 63 | ' | 83 | ||
Mark-to-market derivative liabilities with affiliate (current liabilities) | 0 | ' | 0 | ||
PECO Energy Co [Member] | ' | ' | ' | ||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | ||
Operating revenues from affiliates | 1 | 0 | ' | ||
Purchased power from affiliate | 87 | 141 | ' | ||
Operating and maintenance from affiliate | 24 | 24 | ' | ||
Total interest expense to affiliates, net | 3 | 3 | ' | ||
Dividends paid on common stock | -80 | -83 | ' | ||
Related Party Balance Sheet [Abstract] | ' | ' | ' | ||
Total receivable from affiliates (noncurrent) | 455 | ' | 447 | ||
Investments in affiliates | 8 | ' | 8 | ||
Total payables to affiliates (current) | 60 | ' | 58 | ||
Baltimore Gas and Electric Company [Member] | ' | ' | ' | ||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | ||
Operating revenues from affiliates | 16 | 4 | ' | ||
Purchased power from affiliate | 120 | 113 | ' | ||
Operating and maintenance from affiliate | 25 | 19 | ' | ||
Total interest expense to affiliates, net | 4 | 4 | ' | ||
Dividends paid on common stock | 0 | 0 | ' | ||
Contributions from parent | 0 | 0 | ' | ||
Related Party Balance Sheet [Abstract] | ' | ' | ' | ||
Investments in affiliates | 8 | ' | 8 | ||
Total payables to affiliates (current) | $59 | ' | $55 | ||
[1] | Included in Operating revenues or 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 | |||
In Millions, except Per Share data, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 | ||
Earnings Per Share Basic [Abstract] | ' | ' | ||
Average common shares outstanding - basic | 858 | 855 | ||
Earnings Per Share, Basic | $0.10 | ($0.01) | ||
Earnings Per Share Diluted | ' | ' | ||
Average common shares outstanding - diluted | 861 | 855 | ||
Earnings Per Share, Diluted | $0.10 | ($0.01) | ||
Selected Quarterly Financial Information [Line Items] | ' | ' | ||
Revenues | $7,237 | [1] | $6,082 | [1] |
Operating Income (Loss) | 163 | 508 | ||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 93 | 1 | ||
Exelon Generation Co L L C [Member] | ' | ' | ||
Selected Quarterly Financial Information [Line Items] | ' | ' | ||
Revenues | 4,390 | 3,533 | ||
Operating Income (Loss) | -389 | -64 | ||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | -185 | -17 | ||
Commonwealth Edison Co [Member] | ' | ' | ||
Selected Quarterly Financial Information [Line Items] | ' | ' | ||
Revenues | 1,134 | 1,160 | ||
Operating Income (Loss) | 238 | 209 | ||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 98 | -81 | ||
PECO Energy Co [Member] | ' | ' | ||
Selected Quarterly Financial Information [Line Items] | ' | ' | ||
Revenues | 993 | 895 | ||
Operating Income (Loss) | 149 | 203 | ||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 89 | 122 | ||
Baltimore Gas and Electric Company [Member] | ' | ' | ||
Selected Quarterly Financial Information [Line Items] | ' | ' | ||
Revenues | 1,054 | 880 | ||
Operating Income (Loss) | 169 | 163 | ||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | $88 | $80 | ||
[1] | For the ##D<curmonth> months ended ##D<cyperiod> and ##D<pyfiscal>, utility taxes of $##D<gcytdutiltax> million and $##D<gpytdutiltax> million, respectively, are included in revenues and expenses for Generation. For the ##D<curmonth> months ended ##D<cyperiod> and ##D<pyfiscal>, utility taxes of $##D<ccytdutiltax> million and $##D<cpytdutiltax> million, respectively, are included in revenues and expenses for ComEd. For the ##D<curmonth> months ended ##D<cyperiod> and ##D<pyfiscal>, utility taxes of $##D<pcytdutiltax> million and $##D<ppytdutiltax> million, respectively, are included in revenues and expenses for PECO. For the ##D<curmonth> months ended ##D<cyperiod> and period of March 12, 2012 through ##D<pyperiod>, utility taxes of $##D<bcytdutiltax> million and $##D<bpytdutiltax> million, respectively, are included in revenues and expenses for BGE. |
Subsequent_Event_Details
Subsequent Event (Details) (USD $) | 3 Months Ended |
Mar. 31, 2014 | |
Business Combination, Bargain Purchase [Abstract] | ' |
LineOfCreditFacilityMaximumBorrowingCapacity | $8,400,000,000 |
CashFundingFromNonCoreAssetSale | 1,000,000,000 |
Pepco Holdings [Member] | ' |
Business Combination, Bargain Purchase [Abstract] | ' |
Payments To Acquire Businesses Gross | 27.25 |
LineOfCreditFacilityMaximumBorrowingCapacity | 7,200,000,000 |
BusinessCombinationSeparatelyRecognizedTransactionsAdditionalDisclosuresAcquisitionCosts | 90,000,000 |
DebtFundingPercentage | 50.00% |
OtherlongtermInvestments | 18,000,000 |
Business Combination Proposed Customer Benefits Package | 100,000,000 |
OtherLongTermInvestmentsMaximum | 180,000,000 |
Pepco Holdings [Member] | Maximum [Member] | ' |
Business Combination, Bargain Purchase [Abstract] | ' |
BusinessExitCosts | 293,000,000 |
Pepco Holdings [Member] | Minimum [Member] | ' |
Business Combination, Bargain Purchase [Abstract] | ' |
BusinessExitCosts | $259,000,000 |