Document and Entity Information
Document and Entity Information - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Feb. 05, 2016 | Jun. 30, 2015 | |
Document Information [Line Items] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2015 | ||
Document Fiscal Year Focus | 2,015 | ||
Document Fiscal Period Focus | FY | ||
Trading Symbol | POM | ||
Entity Registrant Name | PEPCO HOLDINGS INC | ||
Entity Central Index Key | 1,135,971 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filers | No | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 254,340,724 | ||
Entity Public Float | $ 6,802.6 | ||
Potomac Electric Power Co [Member] | |||
Document Information [Line Items] | |||
Entity Registrant Name | POTOMAC ELECTRIC POWER CO | ||
Entity Central Index Key | 79,732 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filers | No | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 100 | ||
Entity Public Float | 0 | ||
Delmarva Power & Light Co/De [Member] | |||
Document Information [Line Items] | |||
Entity Registrant Name | DELMARVA POWER & LIGHT CO /DE/ | ||
Entity Central Index Key | 27,879 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filers | No | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 1,000 | ||
Entity Public Float | 0 | ||
Atlantic City Electric Co [Member] | |||
Document Information [Line Items] | |||
Entity Registrant Name | ATLANTIC CITY ELECTRIC CO | ||
Entity Central Index Key | 8,192 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filers | No | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 8,546,017 | ||
Entity Public Float | $ 0 |
Consolidated Statements of Inco
Consolidated Statements of Income (Loss) - USD ($) shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Operating Revenue | $ 5,023 | $ 4,878 | $ 4,666 |
Operating Expenses | |||
Fuel and purchased energy | 2,097 | 2,080 | 2,070 |
Other services cost of sales | 175 | 207 | 146 |
Other operation and maintenance | 1,016 | 924 | 851 |
Depreciation and amortization | 651 | 549 | 473 |
Other taxes | 427 | 413 | 428 |
Deferred electric service costs | 30 | 20 | 26 |
Impairment losses | 81 | 4 | |
Gains on sales of land | (46) | ||
Total Operating Expenses | 4,350 | 4,274 | 3,998 |
Operating Income (Loss) | 673 | 604 | 668 |
Other Income (Expenses) | |||
Interest expense | (280) | (268) | (273) |
Gain from equity investments | 2 | ||
Other income | 54 | 44 | 32 |
Total Other Income (Expenses) | (226) | (224) | (239) |
Income from Continuing Operations Before Income Tax Expense | 447 | 380 | 429 |
Income Tax Expense Related to Continuing Operations | 129 | 138 | 319 |
Net Income (Loss) from Continuing Operations | 318 | 242 | 110 |
Income (Loss) from Discontinued Operations, net of Income Taxes | 9 | (322) | |
Net Income (Loss) | $ 327 | $ 242 | $ (212) |
Basic Share Information | |||
Weighted average shares outstanding - Basic (millions) | 253 | 251 | 246 |
Earnings per share of common stock from Continuing Operations - Basic | $ 1.25 | $ 0.96 | $ 0.45 |
Earnings (loss) per share of common stock from Discontinued Operations - Basic | 0.04 | (1.31) | |
Earnings (loss) per share - Basic | $ 1.29 | $ 0.96 | $ (0.86) |
Diluted Share Information | |||
Weighted average shares outstanding - Diluted (millions) | 254 | 252 | 246 |
Earnings per share of common stock from Continuing Operations - Diluted | $ 1.25 | $ 0.96 | $ 0.45 |
Earnings (loss) per share of common stock from Discontinued Operations - Diluted | 0.04 | (1.31) | |
Earnings (loss) per share - Diluted | $ 1.29 | $ 0.96 | $ (0.86) |
Potomac Electric Power Co [Member] | |||
Operating Revenue | |||
Total Operating Revenue | $ 2,189 | $ 2,101 | $ 2,026 |
Operating Revenue | 2,189 | 2,101 | 2,026 |
Operating Expenses | |||
Fuel and purchased energy | 763 | 771 | 750 |
Other operation and maintenance | 441 | 390 | 391 |
Depreciation and amortization | 277 | 229 | 196 |
Other taxes | 369 | 363 | 368 |
Gains on sales of land | (46) | ||
Total Operating Expenses | 1,804 | 1,753 | 1,705 |
Operating Income (Loss) | 385 | 348 | 321 |
Other Income (Expenses) | |||
Interest expense | (123) | (115) | (110) |
Other income | 23 | 30 | 18 |
Total Other Income (Expenses) | (100) | (85) | (92) |
Income from Continuing Operations Before Income Tax Expense | 285 | 263 | 229 |
Income Tax Expense Related to Continuing Operations | 98 | 92 | 79 |
Net Income (Loss) | 187 | 171 | 150 |
Delmarva Power & Light Co/De [Member] | |||
Operating Revenue | |||
Electric | 1,153 | 1,099 | 1,053 |
Natural gas | 165 | 194 | 191 |
Total Operating Revenue | 1,318 | 1,293 | 1,244 |
Operating Revenue | 1,318 | 1,293 | 1,244 |
Operating Expenses | |||
Fuel and purchased energy | 568 | 546 | 552 |
Gas purchased | 79 | 104 | 109 |
Other operation and maintenance | 306 | 269 | 251 |
Depreciation and amortization | 153 | 125 | 107 |
Other taxes | 47 | 42 | 40 |
Total Operating Expenses | 1,153 | 1,086 | 1,059 |
Operating Income (Loss) | 165 | 207 | 185 |
Other Income (Expenses) | |||
Interest expense | (50) | (48) | (50) |
Other income | 10 | 10 | 10 |
Total Other Income (Expenses) | (40) | (38) | (40) |
Income from Continuing Operations Before Income Tax Expense | 125 | 169 | 145 |
Income Tax Expense Related to Continuing Operations | 49 | 65 | 56 |
Net Income (Loss) | 76 | 104 | 89 |
Atlantic City Electric Co [Member] | |||
Operating Revenue | |||
Total Operating Revenue | 1,298 | 1,213 | 1,202 |
Operating Revenue | 1,298 | 1,213 | 1,202 |
Operating Expenses | |||
Fuel and purchased energy | 685 | 653 | 660 |
Other operation and maintenance | 272 | 246 | 230 |
Depreciation and amortization | 176 | 157 | 136 |
Other taxes | 5 | 2 | 14 |
Deferred electric service costs | 30 | 20 | 26 |
Total Operating Expenses | 1,168 | 1,078 | 1,066 |
Operating Income (Loss) | 130 | 135 | 136 |
Other Income (Expenses) | |||
Interest expense | (64) | (63) | (68) |
Other income | 3 | 1 | 1 |
Total Other Income (Expenses) | (61) | (62) | (67) |
Income from Continuing Operations Before Income Tax Expense | 69 | 73 | 69 |
Income Tax Expense Related to Continuing Operations | 31 | 28 | 19 |
Net Income (Loss) | $ 38 | $ 45 | $ 50 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Statement of Comprehensive Income [Abstract] | |||
Net Income (Loss) | $ 327 | $ 242 | $ (212) |
Other Comprehensive Income (Loss) from Continuing Operations | |||
Losses on treasury rate locks reclassified into income | 1 | 1 | 1 |
Pension and other postretirement benefit plans | 15 | (20) | 13 |
Other comprehensive income (loss), before income taxes | 16 | (19) | 14 |
Income tax expense (benefit) related to other comprehensive income | 6 | (7) | 6 |
Other comprehensive income (loss) from continuing operations, net of income taxes | 10 | (12) | 8 |
Other Comprehensive Income from Discontinued Operations, Net of Income Taxes | 6 | ||
Comprehensive Income (Loss) | $ 337 | $ 230 | $ (198) |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
CURRENT ASSETS | ||
Cash and cash equivalents | $ 25 | $ 14 |
Restricted cash equivalents | 14 | 25 |
Accounts receivable, less allowance for uncollectible accounts | 839 | 782 |
Inventories | 141 | 141 |
Income taxes and related accrued interest receivable | 111 | 9 |
Prepaid expenses and other | 72 | 63 |
Total Current Assets | 1,202 | 1,034 |
OTHER ASSETS | ||
Goodwill | 1,406 | 1,407 |
Regulatory assets | 2,246 | 2,409 |
Deferred income tax assets, net | 15 | 17 |
Income taxes and related accrued interest receivable | 6 | 81 |
Restricted cash equivalents | 18 | 14 |
Other | 129 | 121 |
Total Other Assets | 3,820 | 4,049 |
PROPERTY, PLANT AND EQUIPMENT | ||
Property, plant and equipment | 16,218 | 15,465 |
Accumulated depreciation | (4,914) | (4,959) |
Net Property, Plant and Equipment | 11,304 | 10,506 |
TOTAL ASSETS | 16,326 | 15,589 |
CURRENT LIABILITIES | ||
Short-term debt | 1,063 | 729 |
Current portion of long-term debt and project funding | 341 | 431 |
Current portion of long-term debt | 294 | 366 |
Accounts payable | 175 | 174 |
Accrued liabilities | 322 | 313 |
Capital lease obligations due within one year | 11 | 10 |
Taxes accrued | 51 | 41 |
Interest accrued | 49 | 47 |
Liabilities and accrued interest related to uncertain tax positions | 9 | 6 |
Other | 287 | 305 |
Total Current Liabilities | 2,308 | 2,056 |
DEFERRED CREDITS | ||
Regulatory liabilities | 308 | 343 |
Deferred income tax liabilities, net | 3,393 | 3,242 |
Investment tax credits | 15 | 16 |
Pension benefit obligation | 466 | 396 |
Other postretirement benefit obligations | 215 | 265 |
Other | 202 | 195 |
Total Deferred Credits | 4,599 | 4,457 |
OTHER LONG-TERM LIABILITIES | ||
Long-term debt | 4,656 | 4,397 |
Transition bonds issued by ACE Funding | 124 | 170 |
Long-term project funding | 4 | 8 |
Capital lease obligations | 39 | 50 |
Total Other Long-Term Liabilities | $ 4,823 | $ 4,625 |
COMMITMENTS AND CONTINGENCIES | ||
PREFERRED STOCK | ||
Series A preferred stock, $.01 par value, 18,000 shares authorized, 18,000 and 12,600 shares outstanding, respectively | $ 183 | $ 129 |
EQUITY | ||
Common stock | 3 | 3 |
Premium on stock and other capital contributions | 3,829 | 3,800 |
Accumulated other comprehensive loss | (36) | (46) |
Retained earnings | 617 | 565 |
Total Equity | 4,413 | 4,322 |
TOTAL LIABILITIES AND EQUITY | 16,326 | 15,589 |
Potomac Electric Power Co [Member] | ||
CURRENT ASSETS | ||
Cash and cash equivalents | 5 | 6 |
Restricted cash equivalents | 2 | 5 |
Accounts receivable, less allowance for uncollectible accounts | 346 | 315 |
Inventories | 67 | 62 |
Income taxes and related accrued interest receivable | 170 | 94 |
Prepaid expenses and other | 20 | 21 |
Total Current Assets | 610 | 503 |
OTHER ASSETS | ||
Regulatory assets | 720 | 697 |
Prepaid pension expense | 291 | 316 |
Investment in trust | 27 | 34 |
Income taxes and related accrued interest receivable | 3 | 30 |
Other | 42 | 43 |
Total Other Assets | 1,083 | 1,120 |
PROPERTY, PLANT AND EQUIPMENT | ||
Property, plant and equipment | 8,091 | 7,764 |
Accumulated depreciation | (2,799) | (2,816) |
Net Property, Plant and Equipment | 5,292 | 4,948 |
TOTAL ASSETS | 6,985 | 6,571 |
CURRENT LIABILITIES | ||
Short-term debt | 64 | 104 |
Current portion of long-term debt and project funding | 12 | |
Accounts payable | 87 | 94 |
Accrued liabilities | 101 | 91 |
Accounts payable due to associated companies | 30 | 30 |
Capital lease obligations due within one year | 11 | 10 |
Taxes accrued | 37 | 32 |
Interest accrued | 22 | 19 |
Liabilities and accrued interest related to uncertain tax positions | 3 | |
Customer deposits | 46 | 44 |
Other | 68 | 93 |
Total Current Liabilities | 469 | 529 |
DEFERRED CREDITS | ||
Regulatory liabilities | 92 | 104 |
Deferred income tax liabilities, net | 1,721 | 1,579 |
Investment tax credits | 2 | 2 |
Other postretirement benefit obligations | 49 | 57 |
Other | 72 | 67 |
Total Deferred Credits | 1,936 | 1,809 |
OTHER LONG-TERM LIABILITIES | ||
Long-term debt | 2,301 | 2,096 |
Capital lease obligations | 39 | 50 |
Total Other Long-Term Liabilities | $ 2,340 | $ 2,146 |
COMMITMENTS AND CONTINGENCIES | ||
EQUITY | ||
Premium on stock and other capital contributions | $ 1,122 | $ 1,010 |
Retained earnings | 1,118 | 1,077 |
Total Equity | 2,240 | 2,087 |
TOTAL LIABILITIES AND EQUITY | 6,985 | 6,571 |
Delmarva Power & Light Co/De [Member] | ||
CURRENT ASSETS | ||
Cash and cash equivalents | 5 | 4 |
Restricted cash equivalents | 5 | |
Accounts receivable, less allowance for uncollectible accounts | 203 | 193 |
Inventories | 50 | 55 |
Income taxes and related accrued interest receivable | 58 | 34 |
Prepaid expenses and other | 10 | 12 |
Total Current Assets | 326 | 303 |
OTHER ASSETS | ||
Goodwill | 8 | 8 |
Regulatory assets | 308 | 356 |
Prepaid pension expense | 205 | 220 |
Income taxes and related accrued interest receivable | 4 | |
Other | 1 | 4 |
Total Other Assets | 522 | 592 |
PROPERTY, PLANT AND EQUIPMENT | ||
Property, plant and equipment | 4,209 | 3,946 |
Accumulated depreciation | (1,046) | (1,021) |
Net Property, Plant and Equipment | 3,163 | 2,925 |
TOTAL ASSETS | 4,011 | 3,820 |
CURRENT LIABILITIES | ||
Short-term debt | 210 | 211 |
Current portion of long-term debt | 100 | 100 |
Accounts payable | 41 | 39 |
Accrued liabilities | 76 | 74 |
Accounts payable due to associated companies | 20 | 17 |
Taxes accrued | 3 | 3 |
Interest accrued | 7 | 7 |
Customer deposits | 31 | 24 |
Other | 39 | 41 |
Total Current Liabilities | 527 | 516 |
DEFERRED CREDITS | ||
Regulatory liabilities | 189 | 225 |
Deferred income tax liabilities, net | 941 | 878 |
Investment tax credits | 4 | 4 |
Other postretirement benefit obligations | 19 | 21 |
Other | 33 | 35 |
Total Deferred Credits | 1,186 | 1,163 |
OTHER LONG-TERM LIABILITIES | ||
Long-term debt | $ 1,061 | $ 963 |
COMMITMENTS AND CONTINGENCIES | ||
EQUITY | ||
Premium on stock and other capital contributions | $ 612 | $ 537 |
Retained earnings | 625 | 641 |
Total Equity | 1,237 | 1,178 |
TOTAL LIABILITIES AND EQUITY | 4,011 | 3,820 |
Atlantic City Electric Co [Member] | ||
CURRENT ASSETS | ||
Cash and cash equivalents | 3 | 2 |
Restricted cash equivalents | 12 | 10 |
Accounts receivable, less allowance for uncollectible accounts | 211 | 167 |
Inventories | 23 | 23 |
Income taxes and related accrued interest receivable | 199 | 151 |
Prepaid expenses and other | 1 | 3 |
Total Current Assets | 449 | 356 |
OTHER ASSETS | ||
Regulatory assets | 322 | 427 |
Prepaid pension expense | 83 | 96 |
Income taxes and related accrued interest receivable | 34 | |
Restricted cash equivalents | 18 | 14 |
Other | 4 | 5 |
Total Other Assets | 427 | 576 |
PROPERTY, PLANT AND EQUIPMENT | ||
Property, plant and equipment | 3,305 | 3,073 |
Accumulated depreciation | (764) | (760) |
Net Property, Plant and Equipment | 2,541 | 2,313 |
TOTAL ASSETS | 3,417 | 3,245 |
CURRENT LIABILITIES | ||
Short-term debt | 5 | 127 |
Current portion of long-term debt and project funding | 48 | 59 |
Current portion of long-term debt | 2 | 15 |
Accounts payable | 25 | 20 |
Accrued liabilities | 106 | 103 |
Accounts payable due to associated companies | 16 | 15 |
Taxes accrued | 22 | 1 |
Interest accrued | 13 | 13 |
Customer deposits | 30 | 21 |
Other | 21 | 22 |
Total Current Liabilities | 286 | 381 |
DEFERRED CREDITS | ||
Regulatory liabilities | 27 | 14 |
Deferred income tax liabilities, net | 888 | 855 |
Investment tax credits | 4 | 5 |
Other postretirement benefit obligations | 33 | 36 |
Other | 18 | 16 |
Total Deferred Credits | 970 | 926 |
OTHER LONG-TERM LIABILITIES | ||
Long-term debt | 1,030 | 882 |
Transition bonds issued by ACE Funding | 124 | 170 |
Total Other Long-Term Liabilities | $ 1,154 | $ 1,052 |
COMMITMENTS AND CONTINGENCIES | ||
EQUITY | ||
Common stock | $ 26 | $ 26 |
Premium on stock and other capital contributions | 746 | 651 |
Retained earnings | 235 | 209 |
Total Equity | 1,007 | 886 |
TOTAL LIABILITIES AND EQUITY | $ 3,417 | $ 3,245 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Accounts receivable, allowance for uncollectible accounts | $ 56 | $ 40 |
Series A preferred stock, par value | $ 0.01 | $ 0.01 |
Series A preferred stock, shares authorized | 18,000 | 18,000 |
Series A preferred stock, shares outstanding | 18,000 | 12,600 |
Common stock, par value | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 400,000,000 | 400,000,000 |
Common stock, shares outstanding | 254,289,261 | 252,728,684 |
Potomac Electric Power Co [Member] | ||
Accounts receivable, allowance for uncollectible accounts | $ 17 | $ 16 |
Common stock, par value | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 200,000,000 | 200,000,000 |
Common stock, shares outstanding | 100 | 100 |
Delmarva Power & Light Co/De [Member] | ||
Accounts receivable, allowance for uncollectible accounts | $ 17 | $ 11 |
Common stock, par value | $ 2.25 | $ 2.25 |
Common stock, shares authorized | 1,000 | 1,000 |
Common stock, shares outstanding | 1,000 | 1,000 |
Atlantic City Electric Co [Member] | ||
Accounts receivable, allowance for uncollectible accounts | $ 17 | $ 9 |
Common stock, par value | $ 3 | $ 3 |
Common stock, shares authorized | 25,000,000 | 25,000,000 |
Common stock, shares outstanding | 8,546,017 | 8,546,017 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
OPERATING ACTIVITIES | |||
Net Income (Loss) | $ 327 | $ 242 | $ (212) |
(Income) loss from discontinued operations, net of income taxes | (9) | 322 | |
Adjustments to reconcile net income to net cash from operating activities: | |||
Depreciation and amortization | 651 | 549 | 473 |
Deferred income taxes | 122 | 302 | 458 |
Gains on sales of land | (46) | ||
Losses on treasury rate locks reclassified into income | 1 | 1 | 1 |
Impairment losses | 81 | 4 | |
Increase in fair value of preferred stock derivative | (15) | ||
Other | (2) | (6) | (13) |
Changes in: | |||
Accounts receivable | (56) | 48 | (46) |
Inventories | 7 | 5 | |
Prepaid expenses | 8 | (8) | 17 |
Regulatory assets and liabilities, net | (146) | (216) | (121) |
Accounts payable and accrued liabilities | (14) | (22) | 1 |
Pension contributions | (120) | ||
Pension benefit obligation, excluding contributions | 76 | 48 | 65 |
Cash collateral related to derivative activities | 2 | (9) | 31 |
Income tax-related prepayments, receivables and payables | 32 | (173) | (182) |
Advanced payment made to taxing authority | (242) | ||
Other assets and liabilities | 8 | 10 | 9 |
Net current assets held for disposition or sale | 47 | ||
Net Cash From (Used By) Operating Activities | 939 | 854 | 497 |
INVESTING ACTIVITIES | |||
Investment in property, plant and equipment | (1,230) | (1,223) | (1,310) |
Department of Energy capital reimbursement awards received | 4 | 22 | |
Proceeds from sales of land | 54 | ||
Changes in restricted cash equivalents | 7 | (12) | 1 |
Net other investing activities | 8 | 5 | 3 |
Proceeds from discontinued operations, early termination of finance leases held in trust | 873 | ||
Net Cash Used By Investing Activities | (1,161) | (1,226) | (411) |
FINANCING ACTIVITIES | |||
Dividends paid on common stock | (275) | (272) | (270) |
Common stock issued for the Direct Stock Purchase and Dividend Reinvestment Plan (DRP) and employee-related compensation | 18 | 34 | 50 |
Issuances of common stock | 324 | ||
Issuances of Series A preferred stock | 54 | 126 | |
Issuances of long-term debt | 558 | 766 | 800 |
Reacquisitions of long-term debt | (420) | (334) | (558) |
Issuances (repayments) of short-term debt, net | 34 | 164 | (200) |
Borrowings under term loans | 300 | 250 | |
Repayment of term loan | (100) | (450) | |
Cost of issuances | (7) | (10) | (23) |
Net other financing activities | (29) | (11) | (11) |
Net Cash From (Used By) Financing Activities | 233 | 363 | (88) |
Net Increase (Decrease) In Cash and Cash Equivalents | 11 | (9) | (2) |
Cash and Cash Equivalents at Beginning of Year | 14 | 23 | 25 |
CASH AND CASH EQUIVALENTS AT END OF YEAR | 25 | 14 | 23 |
SUPPLEMENTAL CASH FLOW INFORMATION | |||
Cash paid for interest | 268 | 257 | 260 |
Cash (received) paid for income taxes | (13) | (2) | 228 |
Delmarva Power & Light Co/De [Member] | |||
OPERATING ACTIVITIES | |||
Net Income (Loss) | 76 | 104 | 89 |
Adjustments to reconcile net income to net cash from operating activities: | |||
Depreciation and amortization | 153 | 125 | 107 |
Deferred income taxes | 74 | 111 | 65 |
Investment tax credit amortization | (1) | (1) | (1) |
Changes in: | |||
Accounts receivable | (9) | 15 | (7) |
Inventories | 5 | (4) | 2 |
Regulatory assets and liabilities, net | (38) | (66) | (42) |
Accounts payable and accrued liabilities | 10 | (15) | (1) |
Pension contributions | 0 | 0 | (10) |
Pension benefit obligation, excluding contributions | 15 | 8 | 14 |
Income tax-related prepayments, receivables and payables | (19) | (3) | (1) |
Other assets and liabilities | (6) | (1) | |
Net Cash From (Used By) Operating Activities | 266 | 268 | 214 |
INVESTING ACTIVITIES | |||
Investment in property, plant and equipment | (352) | (352) | (357) |
Net other investing activities | 7 | (6) | 2 |
Net Cash Used By Investing Activities | (345) | (358) | (355) |
FINANCING ACTIVITIES | |||
Dividends paid on common stock | (92) | (100) | (30) |
Capital contributions from Parent | 75 | 130 | |
Issuances of long-term debt | 200 | 204 | 300 |
Reacquisitions of long-term debt | (100) | (100) | (250) |
Issuances (repayments) of short-term debt, net | (1) | (41) | 115 |
Cost of issuances | (2) | (2) | (3) |
Net other financing activities | 1 | 5 | |
Net Cash From (Used By) Financing Activities | 80 | 92 | 137 |
Net Increase (Decrease) In Cash and Cash Equivalents | 1 | 2 | (4) |
Cash and Cash Equivalents at Beginning of Year | 4 | 2 | 6 |
CASH AND CASH EQUIVALENTS AT END OF YEAR | 5 | 4 | 2 |
SUPPLEMENTAL CASH FLOW INFORMATION | |||
Cash paid for interest | 47 | 45 | 47 |
Cash (received) paid for income taxes | (5) | (43) | (8) |
Atlantic City Electric Co [Member] | |||
OPERATING ACTIVITIES | |||
Net Income (Loss) | 38 | 45 | 50 |
Adjustments to reconcile net income to net cash from operating activities: | |||
Depreciation and amortization | 176 | 157 | 136 |
Deferred income taxes | 30 | 37 | 53 |
Investment tax credit amortization | (1) | ||
Changes in: | |||
Accounts receivable | (44) | 18 | 7 |
Inventories | 5 | 2 | |
Regulatory assets and liabilities, net | 21 | 13 | 19 |
Accounts payable and accrued liabilities | 12 | (13) | (1) |
Pension contributions | 0 | 0 | (30) |
Income tax-related prepayments, receivables and payables | 10 | (16) | (6) |
Other assets and liabilities | 13 | 13 | 12 |
Net Cash From (Used By) Operating Activities | 256 | 259 | 241 |
INVESTING ACTIVITIES | |||
Investment in property, plant and equipment | (300) | (225) | (261) |
Department of Energy capital reimbursement awards received | 1 | 2 | |
Net other investing activities | (6) | 3 | |
Net Cash Used By Investing Activities | (306) | (224) | (256) |
FINANCING ACTIVITIES | |||
Dividends paid on common stock | (12) | (26) | (60) |
Capital contributions from Parent | 95 | 75 | |
Issuances of long-term debt | 150 | 150 | 100 |
Reacquisitions of long-term debt | (58) | (48) | (108) |
Issuances (repayments) of short-term debt, net | (122) | (11) | 6 |
Repayment of term loan | (100) | ||
Net other financing activities | (2) | (1) | (1) |
Net Cash From (Used By) Financing Activities | 51 | (36) | 12 |
Net Increase (Decrease) In Cash and Cash Equivalents | 1 | (1) | (3) |
Cash and Cash Equivalents at Beginning of Year | 2 | 3 | 6 |
CASH AND CASH EQUIVALENTS AT END OF YEAR | 3 | 2 | 3 |
SUPPLEMENTAL CASH FLOW INFORMATION | |||
Cash paid for interest | 63 | 61 | 67 |
Cash (received) paid for income taxes | (3) | (21) | |
Potomac Electric Power Co [Member] | |||
OPERATING ACTIVITIES | |||
Net Income (Loss) | 187 | 171 | 150 |
Adjustments to reconcile net income to net cash from operating activities: | |||
Depreciation and amortization | 277 | 229 | 196 |
Deferred income taxes | 149 | 174 | 120 |
Gains on sales of land | (46) | ||
Investment tax credit amortization | (1) | ||
Other | (9) | ||
Changes in: | |||
Accounts receivable | (32) | 27 | (39) |
Inventories | (5) | 5 | 2 |
Prepaid expenses | 2 | (2) | (1) |
Regulatory assets and liabilities, net | (129) | (163) | (99) |
Accounts payable and accrued liabilities | (19) | (34) | 26 |
Pension contributions | 0 | 0 | 0 |
Pension benefit obligation, excluding contributions | 24 | 16 | 21 |
Income tax-related prepayments, receivables and payables | (40) | (25) | (36) |
Interest accrued | 2 | 2 | |
Other assets and liabilities | 3 | (3) | (11) |
Net Cash From (Used By) Operating Activities | 373 | 386 | 330 |
INVESTING ACTIVITIES | |||
Investment in property, plant and equipment | (544) | (567) | (576) |
Department of Energy capital reimbursement awards received | 3 | 20 | |
Proceeds from sales of land | 54 | ||
Changes in restricted cash equivalents | 3 | (3) | (3) |
Net other investing activities | 10 | 7 | (5) |
Net Cash Used By Investing Activities | (477) | (560) | (564) |
FINANCING ACTIVITIES | |||
Dividends paid on common stock | (146) | (86) | (46) |
Capital contributions from Parent | 112 | 80 | 175 |
Issuances of long-term debt | 208 | 412 | 400 |
Reacquisitions of long-term debt | (12) | (175) | (200) |
Issuances (repayments) of short-term debt, net | (40) | (47) | (80) |
Cost of issuances | (4) | (7) | (7) |
Net other financing activities | (15) | (6) | (8) |
Net Cash From (Used By) Financing Activities | 103 | 171 | 234 |
Net Increase (Decrease) In Cash and Cash Equivalents | (1) | (3) | |
Cash and Cash Equivalents at Beginning of Year | 6 | 9 | 9 |
CASH AND CASH EQUIVALENTS AT END OF YEAR | 5 | 6 | 9 |
SUPPLEMENTAL CASH FLOW INFORMATION | |||
Cash paid for interest | 116 | 111 | 102 |
Cash (received) paid for income taxes | $ (6) | $ (58) | $ (28) |
Consolidated Statements of Cas7
Consolidated Statements of Cash Flows (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Capitalized interest | $ 8 | $ 8 | $ 7 |
Delmarva Power & Light Co/De [Member] | |||
Capitalized interest | 1 | 1 | 2 |
Atlantic City Electric Co [Member] | |||
Capitalized interest | 1 | 1 | 1 |
Potomac Electric Power Co [Member] | |||
Capitalized interest | $ 7 | $ 5 | $ 5 |
Consolidated Statements of Equi
Consolidated Statements of Equity - USD ($) $ in Millions | Total | Common Stock [Member] | Premium on Stock [Member] | Retained Earnings [Member] | Accumulated Other Comprehensive (Loss) Income [Member] | Potomac Electric Power Co [Member] | Potomac Electric Power Co [Member]Common Stock [Member] | Potomac Electric Power Co [Member]Premium on Stock [Member] | Potomac Electric Power Co [Member]Retained Earnings [Member] | Delmarva Power & Light Co/De [Member] | Delmarva Power & Light Co/De [Member]Common Stock [Member] | Delmarva Power & Light Co/De [Member]Premium on Stock [Member] | Delmarva Power & Light Co/De [Member]Retained Earnings [Member] | Atlantic City Electric Co [Member] | Atlantic City Electric Co [Member]Common Stock [Member] | Atlantic City Electric Co [Member]Premium on Stock [Member] | Atlantic City Electric Co [Member]Retained Earnings [Member] |
Balance at Dec. 31, 2012 | $ 4,414 | $ 2 | $ 3,383 | $ 1,077 | $ (48) | $ 1,643 | $ 755 | $ 888 | $ 985 | $ 407 | $ 578 | $ 802 | $ 26 | $ 576 | $ 200 | ||
Balance, Shares at Dec. 31, 2012 | 230,015,427 | 100 | 1,000 | 8,546,017 | |||||||||||||
Net Income (Loss) | (212) | (212) | 150 | 150 | 89 | 89 | 50 | 50 | |||||||||
Other comprehensive income (loss) | 14 | 14 | |||||||||||||||
Capital contribution from Parent | 175 | 175 | 75 | 75 | |||||||||||||
Dividends on common stock | (270) | (270) | (46) | (46) | (30) | (30) | (60) | (60) | |||||||||
Issuance of common stock: | |||||||||||||||||
Original issue shares, net | 332 | $ 1 | 331 | ||||||||||||||
Original issue shares, net, shares | 18,734,128 | ||||||||||||||||
DRP original issue shares | $ 30 | 30 | |||||||||||||||
DRP original issue shares, shares | 2,000,000 | 1,575,343 | |||||||||||||||
Net activity related to stock-based awards | $ 7 | 7 | |||||||||||||||
Balance at Dec. 31, 2013 | 4,315 | $ 3 | 3,751 | 595 | (34) | 1,922 | 930 | 992 | 1,044 | 407 | 637 | 867 | $ 26 | 651 | 190 | ||
Balance, Shares at Dec. 31, 2013 | 250,324,898 | 100 | 1,000 | 8,546,017 | |||||||||||||
Net Income (Loss) | 242 | 242 | 171 | 171 | 104 | 104 | 45 | 45 | |||||||||
Other comprehensive income (loss) | (12) | (12) | |||||||||||||||
Capital contribution from Parent | 80 | 80 | 130 | 130 | |||||||||||||
Dividends on common stock | (272) | (272) | (86) | (86) | (100) | (100) | (26) | (26) | |||||||||
Issuance of common stock: | |||||||||||||||||
Original issue shares, net | 14 | 14 | |||||||||||||||
Original issue shares, net, shares | 1,310,276 | ||||||||||||||||
DRP original issue shares | $ 28 | 28 | |||||||||||||||
DRP original issue shares, shares | 1,000,000 | 1,122,575 | |||||||||||||||
Net activity related to stock-based awards | $ 7 | 7 | |||||||||||||||
Net activity related to stock-based awards, shares | (29,065) | ||||||||||||||||
Balance at Dec. 31, 2014 | $ 4,322 | $ 3 | 3,800 | 565 | (46) | $ 2,087 | 1,010 | 1,077 | $ 1,178 | 537 | 641 | $ 886 | $ 26 | 651 | 209 | ||
Balance, Shares at Dec. 31, 2014 | 252,728,684 | 252,728,684 | 100 | 100 | 1,000 | 1,000 | 8,546,017 | 8,546,017 | |||||||||
Net Income (Loss) | $ 327 | 327 | $ 187 | 187 | $ 76 | 76 | $ 38 | 38 | |||||||||
Other comprehensive income (loss) | 10 | 10 | |||||||||||||||
Capital contribution from Parent | 112 | 112 | 75 | 75 | 95 | 95 | |||||||||||
Dividends on common stock | (275) | (275) | (146) | (146) | (92) | (92) | (12) | (12) | |||||||||
Issuance of common stock: | |||||||||||||||||
Original issue shares, net | 15 | 15 | |||||||||||||||
Original issue shares, net, shares | 1,157,203 | ||||||||||||||||
DRP original issue shares | $ 11 | 11 | |||||||||||||||
DRP original issue shares, shares | 1,000,000 | 397,939 | |||||||||||||||
Net activity related to stock-based awards | $ 3 | 3 | |||||||||||||||
Net activity related to stock-based awards, shares | 5,435 | ||||||||||||||||
Balance at Dec. 31, 2015 | $ 4,413 | $ 3 | $ 3,829 | $ 617 | $ (36) | $ 2,240 | $ 1,122 | $ 1,118 | $ 1,237 | $ 612 | $ 625 | $ 1,007 | $ 26 | $ 746 | $ 235 | ||
Balance, Shares at Dec. 31, 2015 | 254,289,261 | 254,289,261 | 100 | 100 | 1,000 | 1,000 | 8,546,017 | 8,546,017 |
Consolidated Statements of Equ9
Consolidated Statements of Equity (Parenthetical) - $ / shares | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Statement of Stockholders' Equity [Abstract] | |||||||||||
Dividends on common stock, per share | $ 0.27 | $ 0.27 | $ 0.27 | $ 0.27 | $ 0.27 | $ 0.27 | $ 0.27 | $ 0.27 | $ 1.08 | $ 1.08 | $ 1.08 |
Organization
Organization | 12 Months Ended |
Dec. 31, 2015 | |
Organization | (1) ORGANIZATION Pepco Holdings, Inc. (PHI or Pepco Holdings), a Delaware corporation incorporated in 2001, is a holding company that, through the following regulated public utility subsidiaries, is engaged primarily in the transmission, distribution and default supply of electricity and, to a lesser extent, the distribution and supply of natural gas (Power Delivery): • Potomac Electric Power Company (Pepco), which was incorporated in Washington, D.C. in 1896 and became a domestic Virginia corporation in 1949, • Delmarva Power & Light Company (DPL), which was incorporated in Delaware in 1909 and became a domestic Virginia corporation in 1979, and • Atlantic City Electric Company (ACE), which was incorporated in New Jersey in 1924. Each of PHI, Pepco, DPL and ACE is also a reporting company under the Securities Exchange Act of 1934, as amended. Together, Pepco, DPL and ACE constitute the Power Delivery segment for financial reporting purposes. Through Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services), PHI provides energy savings performance contracting services, underground transmission and distribution construction and maintenance services, and steam and chilled water under long-term contracts. PHI Service Company, a wholly owned subsidiary service company of PHI, provides a variety of support services, including legal, accounting, treasury, tax, purchasing and information technology services to PHI and its operating subsidiaries. These services are provided pursuant to service agreements among PHI, PHI Service Company and the participating operating subsidiaries. The expenses of PHI Service Company are charged to PHI and the participating operating subsidiaries in accordance with cost allocation methodologies set forth in the service agreements. Agreement and Plan of Merger with Exelon Corporation PHI entered into an Agreement and Plan of Merger, dated April 29, 2014, as amended and restated on July 18, 2014 (the Merger Agreement), with Exelon Corporation, a Pennsylvania corporation (Exelon), and Purple Acquisition Corp., a Delaware corporation and an indirect, wholly owned subsidiary of Exelon (Merger Sub), providing for the merger of Merger Sub with and into PHI (the Merger), with PHI surviving the Merger as an indirect, wholly owned subsidiary of Exelon. Pursuant to the Merger Agreement, at the effective time of the Merger, each outstanding share of common stock, par value $0.01 per share, of PHI (other than (i) shares owned by Exelon, Merger Sub or any other direct or indirect wholly owned subsidiary of Exelon and shares owned by PHI or any direct or indirect, wholly owned subsidiary of PHI, and in each case not held on behalf of third parties (but not including shares held by PHI in any rabbi trust or similar arrangement in respect of any compensation plan or arrangement) and (ii) shares that are owned by stockholders who have perfected and not withdrawn a demand for appraisal rights pursuant to Delaware law), will be canceled and converted into the right to receive $27.25 in cash, without interest. In connection with entering into the Merger Agreement, as further described in Note (13), “Preferred Stock,” PHI entered into a Subscription Agreement with Exelon dated April 29, 2014 (the Subscription Agreement), pursuant to which PHI issued to Exelon 9,000 originally issued shares of non-voting, non-convertible and non-transferable Series A preferred stock, par value $0.01 per share (the Preferred Stock), for a purchase price of $90 million on April 30, 2014. Exelon also committed, pursuant to the Subscription Agreement, to purchase 1,800 originally issued shares of Preferred Stock for a purchase price of $18 million at the end of each 90-day period following the date of the Subscription Agreement until the Merger closes or is terminated, up to a maximum of 18,000 shares of Preferred Stock for a maximum aggregate consideration of $180 million. In accordance with the Subscription Agreement, on each of July 29, 2014, October 27, 2014, January 26, 2015, April 27, 2015 and July 24, 2015, an additional 1,800 shares of Preferred Stock were issued by PHI to Exelon for an aggregate purchase price of $90 million. The Merger Agreement provides for certain termination rights for each of PHI and Exelon, and further provides that, upon termination of the Merger Agreement under certain specified circumstances, PHI will be required to pay Exelon a termination fee of $259 million or reimburse Exelon for its expenses up to $40 million (which reimbursement of expenses shall reduce on a dollar for dollar basis any termination fee subsequently payable by PHI), provided, however, that if the Merger Agreement is terminated in connection with an acquisition proposal made under certain circumstances by a person who made an acquisition proposal between April 1, 2014 and the date of the Merger Agreement, the termination fee will be $293 million plus reimbursement of Exelon for its expenses up to $40 million (not subject to offset). In addition, if the Merger Agreement is terminated under certain circumstances due to the failure to obtain required regulatory approvals with respect to the Merger or the breach by Exelon of its obligations in respect of obtaining such regulatory approvals (a Regulatory Termination), PHI will be able to redeem any issued and outstanding Preferred Stock at par value, and in that case, Exelon will be required to pay all documented out-of-pocket expenses incurred by PHI in connection with the Merger Agreement or the transactions contemplated thereby, up to $40 million. If the Merger Agreement is terminated, other than for a Regulatory Termination, PHI will be required to redeem the Preferred Stock at the purchase price of $10,000 per share, plus any unpaid accrued and accumulated dividends thereupon. Consummation of the Merger is subject to the satisfaction or waiver of specified closing conditions, including (i) the approval of the Merger by the holders of a majority of the outstanding shares of common stock of PHI; (ii) the receipt of regulatory approvals required to consummate the Merger, including approvals from the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission (FCC), the Delaware Public Service Commission (DPSC), the District of Columbia Public Service Commission (DCPSC), the Maryland Public Service Commission (MPSC), the New Jersey Board of Public Utilities (NJBPU) and the Virginia State Corporation Commission (VSCC); (iii) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (the HSR Act); and (iv) other customary closing conditions, including (a) the accuracy of each party’s representations and warranties (subject to customary materiality qualifiers) and (b) each party’s compliance with its obligations and covenants contained in the Merger Agreement (including covenants that may limit, restrict or prohibit PHI and its subsidiaries from taking specified actions during the period between the date of the Merger Agreement and the closing of the Merger or the termination of the Merger Agreement). In addition, the obligations of Exelon and Merger Sub to consummate the Merger are subject to the required regulatory approvals not imposing terms, conditions, obligations or commitments, individually or in the aggregate, that constitute a burdensome condition (as defined in the Merger Agreement). For additional discussion, see Note (7), “Regulatory Matters – Merger Approval Proceedings.” On September 23, 2014, the stockholders of PHI approved the Merger, on October 7, 2014, the VSCC approved the Merger, and on November 20, 2014, FERC approved the Merger. In addition, the transfer of control of certain communications licenses held by certain of PHI’s subsidiaries has been approved by the FCC. The NJBPU approved the Merger on February 11, 2015 and, on October 15, 2015, voted to extend the effectiveness of its approval until June 30, 2016. The DPSC approved the Merger on May 19, 2015. The waiting period expired under the HSR Act on December 2, 2015, which allows for the closing of the Merger at any time on or before December 1, 2016. On May 15, 2015, the MPSC approved the Merger, with conditions, including conditions that modify and supplement those originally proposed. On May 18, 2015, PHI and Exelon announced that they had committed to fulfill the modified, more stringent conditions and package of customer benefits imposed by the MPSC. In connection with these proceedings, the Maryland Office of People’s Counsel and several other parties to the Merger proceedings filed motions in the Circuit Court for Queen Anne’s County, Maryland, requesting a stay of the MPSC order. On August 7, 2015, the Circuit Court for Queen Anne’s County denied the motions for stay. On January 8, 2016, the Circuit Court affirmed the MPSC’s order in all respects. On January 20 and 22, 2016, respectively, the Maryland Office of People’s Counsel and environmental groups filed notices of appeal of the Circuit Court’s order to the Maryland Court of Special Appeals. Unless a motion to stay is filed and then granted by the court, the MPSC order will remain in effect during the appeals process. On August 27, 2015, the DCPSC issued a written order denying the application seeking approval of the Merger. On September 28, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, filed an application for reconsideration with the DCPSC requesting reconsideration of the DCPSC order related to the Merger. On October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, entered into a Nonunanimous Full Settlement Agreement and Stipulation (the DC Settlement Agreement) with the District of Columbia Government, the Office of the People’s Counsel and other parties, which DC Settlement Agreement contains commitments from Exelon and PHI above those contained in their original merger application. Also on October 6, 2015, PHI, Exelon and Merger Sub entered into a Letter Agreement (the Letter Agreement), setting forth the terms and conditions under which the parties will file with the DCPSC (a) a Motion of Joint Applicants to Reopen the Record in Formal Case No. 1119 to Allow for Consideration of the DC Settlement Agreement (the Motion to Reopen), or (b) if the Motion to Reopen is not granted, a new merger application, requesting approval of the Merger on the terms and commitments agreed to in the DC Settlement Agreement. Pursuant to the Letter Agreement, PHI and Exelon each agrees, among other things, that neither party will exercise the termination rights each may have under the Merger Agreement on or after October 29, 2015, unless: (i) the DCPSC does not, by November 20, 2015, set a procedural schedule which allows for a final order for approval of the Merger by March 4, 2016, (ii) the DCPSC sets a schedule for action which does not allow for a final order for approval of the Merger by March 4, 2016, (iii) the DCPSC fails to issue a final order approving the Merger and the DC Settlement Agreement as filed without condition or modification by March 4, 2016, (iv) the DCPSC issues a final order denying approval of the Merger or the DC Settlement Agreement or adds conditions or makes modifications to the DC Settlement Agreement, (v) the DC Settlement Agreement is terminated for any reason, or (vi) after March 4, 2016 a condition to closing of the Merger has not been satisfied or waived (other than those conditions that by their nature are to be satisfied at the closing). The Letter Agreement also provides that, subject to certain conditions, Exelon may, following receipt of all regulatory approvals consistent with the DC Settlement Agreement, delay closing of the Merger for up to 30 days to engage in capital markets transactions to raise additional funds required to consummate the Merger. On October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, filed with the DCPSC the Motion to Reopen requesting consideration of the DC Settlement Agreement and approval of the Merger on such terms and conditions set forth in the DC Settlement Agreement, without condition or modification, and to stay further proceedings on the application for reconsideration filed by the parties on September 28, 2015 and suspend the time period for reconsideration pending the DCPSC’s consideration of the DC Settlement Agreement. On October 28, 2015, the DCPSC approved the Motion to Reopen and set a procedural schedule for its review of this matter. Upon completion of the public input and evidentiary hearings, the record was closed as of December 23, 2015. Although District of Columbia law does not impose any time limit on the DCPSC’s review of the Merger, the parties requested a decision by March 4, 2016. Power Delivery Each of Pepco, DPL and ACE is a regulated public utility in the jurisdictions that comprise its service territory. Each utility owns and operates a network of wires, substations and other equipment that is classified as transmission facilities, distribution facilities or common facilities (which are used for both transmission and distribution). Transmission facilities are high-voltage systems that carry wholesale electricity into, or across, the utility’s service territory. Distribution facilities are low-voltage systems that carry electricity to end-use customers in the utility’s service territory. Each utility is responsible for the distribution of electricity, and in the case of DPL, the distribution and supply of natural gas, in its service territory, for which it is paid tariff rates established by the applicable local public service commissions. Each utility also supplies electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive energy supplier. The regulatory term for this supply service is Standard Offer Service (SOS) in Delaware, the District of Columbia and Maryland, and Basic Generation Service in New Jersey. These supply service obligations are referred to generally as Default Electricity Supply. Pepco Energy Services Pepco Energy Services is engaged in the following businesses: • Energy savings performance contracting: designing, constructing and operating energy efficiency projects and distributed generation equipment, including combined heat and power plants, principally for federal, state and local government customers; • Underground transmission and distribution: providing underground transmission and distribution construction and maintenance services for electric utilities in North America; and • Thermal: providing steam and chilled water under long-term contracts through systems owned and operated by Pepco Energy Services, primarily to hotels and casinos in Atlantic City, New Jersey. During 2012, Pepco Energy Services deactivated its Buzzard Point and Benning Road oil-fired generation facilities. Pepco Energy Services completed demolition of the Benning Road generation facility in July 2015 and recognized the scrap metal salvage value of the facility as a reduction in its demolition expenses over the life of the project. Corporate and Other Corporate and Other includes the remaining operations of the former Other Non-Regulated segment, certain parent company transactions (including interest expense on parent company debt and incremental external merger-related costs) and inter-company eliminations. Discontinued Operations Cross-Border Energy Lease Investments Through its subsidiary PCI, PHI held a portfolio of cross-border energy lease investments. During 2013, PHI completed the termination of its interest in its cross-border energy lease investments and, as a result, these investments have been accounted for as discontinued operations. Pepco Energy Services In December 2009, PHI announced the wind-down of the retail energy supply component of the Pepco Energy Services business which was comprised of the retail electric and natural gas supply businesses. Pepco Energy Services implemented the wind-down by not entering into any new retail electric or natural gas supply contracts while continuing to perform under its existing retail electric and natural gas supply contracts through their respective expiration dates. On March 21, 2013, Pepco Energy Services entered into an agreement whereby a third party assumed all the rights and obligations of the remaining retail natural gas supply customer contracts, and the associated supply obligations, inventory and derivative contracts. The transaction was completed on April 1, 2013. In addition, Pepco Energy Services completed the wind-down of its retail electric supply business in the second quarter of 2013 by terminating its remaining customer supply and wholesale purchase obligations beyond June 30, 2013. The operations of Pepco Energy Services’ retail electric and natural gas supply businesses have been classified as discontinued operations and are no longer a part of the Pepco Energy Services segment for financial reporting purposes. |
Potomac Electric Power Co [Member] | |
Organization | (1) ORGANIZATION Potomac Electric Power Company (Pepco) is engaged in the transmission and distribution of electricity in the District of Columbia and major portions of Prince George’s County and Montgomery County in suburban Maryland. Pepco also provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territories who do not elect to purchase electricity from a competitive supplier. Default Electricity Supply is known as Standard Offer Service in both the District of Columbia and Maryland. Pepco is a wholly owned subsidiary of Pepco Holdings, Inc. (Pepco Holdings or PHI). PHI entered into an Agreement and Plan of Merger, dated April 29, 2014, as amended and restated on July 18, 2014 (the Merger Agreement), with Exelon Corporation, a Pennsylvania corporation (Exelon), and Purple Acquisition Corp., a Delaware corporation and an indirect, wholly owned subsidiary of Exelon (Merger Sub), providing for the merger of Merger Sub with and into PHI (the Merger), with PHI surviving the Merger as an indirect, wholly owned subsidiary of Exelon. Pursuant to the Merger Agreement, at the effective time of the Merger, each outstanding share of common stock, par value $0.01 per share, of PHI (other than (i) shares owned by Exelon, Merger Sub or any other direct or indirect wholly owned subsidiary of Exelon and shares owned by PHI or any direct or indirect wholly owned subsidiary of PHI, and in each case not held on behalf of third parties (but not including shares held by PHI in any rabbi trust or similar arrangement in respect of any compensation plan or arrangement) and (ii) shares that are owned by stockholders who have perfected and not withdrawn a demand for appraisal rights pursuant to Delaware law), will be canceled and converted into the right to receive $27.25 in cash, without interest. In connection with entering into the Merger Agreement, PHI entered into a Subscription Agreement, dated April 29, 2014 (the Subscription Agreement), with Exelon, pursuant to which on April 30, 2014, PHI issued to Exelon 9,000 originally issued shares of non-voting, non-convertible and non-transferable Series A preferred stock, par value $0.01 per share (the Preferred Stock), for a purchase price of $90 million. Exelon also committed pursuant to the Subscription Agreement to purchase 1,800 originally issued shares of Preferred Stock for a purchase price of $18 million at the end of each 90-day period following the date of the Subscription Agreement until the Merger closes or is terminated, up to a maximum of 18,000 shares of Preferred Stock for a maximum aggregate consideration of $180 million. In accordance with the Subscription Agreement, on each of July 29, 2014, October 27, 2014, January 26, 2015, April 27, 2015 and July 24, 2015, an additional 1,800 shares of Preferred Stock were issued by PHI to Exelon for an aggregate purchase price of $90 million. The holders of the Preferred Stock will be entitled to receive a cumulative, non-participating cash dividend of 0.1% per annum, payable quarterly, when, as and if declared by PHI’s board of directors. The proceeds from the issuance of the Preferred Stock are not subject to restrictions and are intended to serve as a prepayment of any applicable reverse termination fee payable from Exelon to PHI. The Preferred Stock will be redeemable on the terms and in the circumstances set forth in the Merger Agreement and the Subscription Agreement. The Merger Agreement provides for certain termination rights for each of PHI and Exelon, and further provides that, upon termination of the Merger Agreement under certain specified circumstances, PHI will be required to pay Exelon a termination fee of $259 million or reimburse Exelon for its expenses up to $40 million (which reimbursement of expenses shall reduce on a dollar for dollar basis any termination fee subsequently payable by PHI), provided, however, that if the Merger Agreement is terminated in connection with an acquisition proposal made under certain circumstances by a person who made an acquisition proposal between April 1, 2014 and the date of the Merger Agreement, the termination fee will be $293 million plus reimbursement of Exelon for its expenses up to $40 million (not subject to offset). In addition, if the Merger Agreement is terminated under certain circumstances due to the failure to obtain required regulatory approvals with respect to the Merger or the breach by Exelon of its obligations in respect of obtaining such regulatory approvals (a Regulatory Termination), PHI will be able to redeem any issued and outstanding Preferred Stock at par value, and in that case, Exelon will be required to pay all documented out-of-pocket expenses incurred by PHI in connection with the Merger Agreement or the transactions contemplated thereby, up to $40 million. If the Merger Agreement is terminated, other than for a Regulatory Termination, PHI will be required to redeem the Preferred Stock at the purchase price of $10,000 per share, plus any unpaid accrued and accumulated dividends thereupon. Consummation of the Merger is subject to the satisfaction or waiver of specified closing conditions, including (i) the approval of the Merger by the holders of a majority of the outstanding shares of common stock of PHI; (ii) the receipt of regulatory approvals required to consummate the Merger, including approvals from the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission (FCC), the Delaware Public Service Commission (DPSC), the District of Columbia Public Service Commission (DCPSC), the Maryland Public Service Commission (MPSC), the New Jersey Board of Public Utilities (NJBPU) and the Virginia State Corporation Commission (VSCC); (iii) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (the HSR Act); and (iv) other customary closing conditions, including (a) the accuracy of each party’s representations and warranties (subject to customary materiality qualifiers) and (b) each party’s compliance with its obligations and covenants contained in the Merger Agreement (including covenants that may limit, restrict or prohibit PHI and its subsidiaries from taking specified actions during the period between the date of the Merger Agreement and the closing of the Merger or the termination of the Merger Agreement). In addition, the obligations of Exelon and Merger Sub to consummate the Merger are subject to the required regulatory approvals not imposing terms, conditions, obligations or commitments, individually or in the aggregate, that constitute a burdensome condition (as defined in the Merger Agreement). For additional discussion, see Note (6), “Regulatory Matters – Merger Approval Proceedings.” On September 23, 2014, the stockholders of PHI approved the Merger, on October 7, 2014, the VSCC approved the Merger, and on November 20, 2014, FERC approved the Merger. In addition, the transfer of control of certain communications licenses held by certain of PHI’s subsidiaries has been approved by the FCC. The NJBPU approved the Merger on February 11, 2015 and, on October 15, 2015, voted to extend the effectiveness of its approval until June 30, 2016. The DPSC approved the Merger on May 19, 2015. The waiting period expired under the HSR Act on December 2, 2015, which allows for the closing of the Merger at any time on or before December 1, 2016. On May 15, 2015, the MPSC approved the Merger, with conditions, including conditions that modify and supplement those originally proposed. On May 18, 2015, PHI and Exelon announced that they had committed to fulfill the modified, more stringent conditions and package of customer benefits imposed by the MPSC. In connection with these proceedings, the Maryland Office of People’s Counsel and several other parties to the Merger proceedings filed motions in the Circuit Court for Queen Anne’s County, Maryland, requesting a stay of the MPSC order. On August 7, 2015, the Circuit Court for Queen Anne’s County denied the motions for stay. On January 8, 2016, the Circuit Court affirmed the MPSC’s order in all respects. On January 20 and 22, 2016, respectively, the Maryland Office of People’s Counsel and environmental groups filed notices of appeal of the Circuit Court’s order to the Maryland Court of Special Appeals. Unless a motion to stay is filed and then granted by the court, the MPSC order will remain in effect during the appeals process. On August 27, 2015, the DCPSC issued a written order denying the application seeking approval of the Merger. On September 28, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, filed an application for reconsideration with the DCPSC requesting reconsideration of the DCPSC order related to the Merger. On October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, entered into a Nonunanimous Full Settlement Agreement and Stipulation (the DC Settlement Agreement) with the District of Columbia Government, the Office of the People’s Counsel and other parties, which DC Settlement Agreement contains commitments from Exelon and PHI above those contained in their original merger application. Also on October 6, 2015, PHI, Exelon and Merger Sub entered into a Letter Agreement (the Letter Agreement), setting forth the terms and conditions under which the parties will file with the DCPSC (a) a Motion of Joint Applicants to Reopen the Record in Formal Case No. 1119 to Allow for Consideration of the DC Settlement Agreement (the Motion to Reopen), or (b) if the Motion to Reopen is not granted, a new merger application, requesting approval of the Merger on the terms and commitments agreed to in the DC Settlement Agreement. Pursuant to the Letter Agreement, PHI and Exelon each agrees, among other things, that neither party will exercise the termination rights each may have under the Merger Agreement on or after October 29, 2015, unless: (i) the DCPSC does not, by November 20, 2015, set a procedural schedule which allows for a final order for approval of the Merger by March 4, 2016, (ii) the DCPSC sets a schedule for action which does not allow for a final order for approval of the Merger by March 4, 2016, (iii) the DCPSC fails to issue a final order approving the Merger and the DC Settlement Agreement as filed without condition or modification by March 4, 2016, (iv) the DCPSC issues a final order denying approval of the Merger or the DC Settlement Agreement or adds conditions or makes modifications to the DC Settlement Agreement, (v) the DC Settlement Agreement is terminated for any reason, or (vi) after March 4, 2016 a condition to closing of the Merger has not been satisfied or waived (other than those conditions that by their nature are to be satisfied at the closing). The Letter Agreement also provides that, subject to certain conditions, Exelon may, following receipt of all regulatory approvals consistent with the DC Settlement Agreement, delay closing of the Merger for up to 30 days to engage in capital markets transactions to raise additional funds required to consummate the Merger. On October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, filed with the DCPSC the Motion to Reopen requesting consideration of the DC Settlement Agreement and approval of the Merger on such terms and conditions set forth in the DC Settlement Agreement, without condition or modification, and to stay further proceedings on the application for reconsideration filed by the parties on September 28, 2015 and suspend the time period for reconsideration pending the DCPSC’s consideration of the DC Settlement Agreement. On October 28, 2015, the DCPSC approved the Motion to Reopen and set a procedural schedule for its review of this matter. Upon completion of the public input and evidentiary hearings, the record was closed as of December 23, 2015. Although District of Columbia law does not impose any time limit on the DCPSC’s review of the Merger, the parties requested a decision by March 4, 2016. |
Delmarva Power & Light Co/De [Member] | |
Organization | (1) ORGANIZATION Delmarva Power & Light Company (DPL) is engaged in the transmission and distribution of electricity in portions of Delaware and Maryland and provides natural gas distribution service in northern Delaware. Additionally, DPL provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territories who do not elect to purchase electricity from a competitive supplier. Default Electricity Supply is known as Standard Offer Service in both Delaware and Maryland. DPL is a wholly owned subsidiary of Conectiv, LLC (Conectiv), which is wholly owned by Pepco Holdings, Inc. (Pepco Holdings or PHI). PHI entered into an Agreement and Plan of Merger, dated April 29, 2014, as amended and restated on July 18, 2014 (the Merger Agreement), with Exelon Corporation, a Pennsylvania corporation (Exelon), and Purple Acquisition Corp., a Delaware corporation and an indirect, wholly owned subsidiary of Exelon (Merger Sub), providing for the merger of Merger Sub with and into PHI (the Merger), with PHI surviving the Merger as an indirect, wholly owned subsidiary of Exelon. Pursuant to the Merger Agreement, at the effective time of the Merger, each outstanding share of common stock, par value $0.01 per share, of PHI (other than (i) shares owned by Exelon, Merger Sub or any other direct or indirect wholly owned subsidiary of Exelon and shares owned by PHI or any direct or indirect wholly owned subsidiary of PHI, and in each case not held on behalf of third parties (but not including shares held by PHI in any rabbi trust or similar arrangement in respect of any compensation plan or arrangement) and (ii) shares that are owned by stockholders who have perfected and not withdrawn a demand for appraisal rights pursuant to Delaware law), will be canceled and converted into the right to receive $27.25 in cash, without interest. In connection with entering into the Merger Agreement, PHI entered into a Subscription Agreement, dated April 29, 2014 (the Subscription Agreement), with Exelon, pursuant to which on April 30, 2014, PHI issued to Exelon 9,000 originally issued shares of non-voting, non-convertible and non-transferable Series A preferred stock, par value $0.01 per share (the Preferred Stock), for a purchase price of $90 million. Exelon also committed pursuant to the Subscription Agreement to purchase 1,800 originally issued shares of Preferred Stock for a purchase price of $18 million at the end of each 90-day period following the date of the Subscription Agreement until the Merger closes or is terminated, up to a maximum of 18,000 shares of Preferred Stock for a maximum aggregate consideration of $180 million. In accordance with the Subscription Agreement, on each of July 29, 2014, October 27, 2014, January 26, 2015, April 27, 2015 and July 24, 2015, an additional 1,800 shares of Preferred Stock were issued by PHI to Exelon for an aggregate purchase price of $90 million. The holders of the Preferred Stock will be entitled to receive a cumulative, non-participating cash dividend of 0.1% per annum, payable quarterly, when, as and if declared by PHI’s board of directors. The proceeds from the issuance of the Preferred Stock are not subject to restrictions and are intended to serve as a prepayment of any applicable reverse termination fee payable from Exelon to PHI. The Preferred Stock will be redeemable on the terms and in the circumstances set forth in the Merger Agreement and the Subscription Agreement. The Merger Agreement provides for certain termination rights for each of PHI and Exelon, and further provides that, upon termination of the Merger Agreement under certain specified circumstances, PHI will be required to pay Exelon a termination fee of $259 million or reimburse Exelon for its expenses up to $40 million (which reimbursement of expenses shall reduce on a dollar for dollar basis any termination fee subsequently payable by PHI), provided, however, that if the Merger Agreement is terminated in connection with an acquisition proposal made under certain circumstances by a person who made an acquisition proposal between April 1, 2014 and the date of the Merger Agreement, the termination fee will be $293 million plus reimbursement of Exelon for its expenses up to $40 million (not subject to offset). In addition, if the Merger Agreement is terminated under certain circumstances due to the failure to obtain required regulatory approvals with respect to the Merger or the breach by Exelon of its obligations in respect of obtaining such regulatory approvals (a Regulatory Termination), PHI will be able to redeem any issued and outstanding Preferred Stock at par value, and in that case, Exelon will be required to pay all documented out-of-pocket expenses incurred by PHI in connection with the Merger Agreement or the transactions contemplated thereby, up to $40 million. If the Merger Agreement is terminated, other than for a Regulatory Termination, PHI will be required to redeem the Preferred Stock at the purchase price of $10,000 per share, plus any unpaid accrued and accumulated dividends thereupon. Consummation of the Merger is subject to the satisfaction or waiver of specified closing conditions, including (i) the approval of the Merger by the holders of a majority of the outstanding shares of common stock of PHI; (ii) the receipt of regulatory approvals required to consummate the Merger, including approvals from the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission (FCC), the Delaware Public Service Commission (DPSC), the District of Columbia Public Service Commission (DCPSC), the Maryland Public Service Commission (MPSC), the New Jersey Board of Public Utilities (NJBPU) and the Virginia State Corporation Commission (VSCC); (iii) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (the HSR Act); and (iv) other customary closing conditions, including (a) the accuracy of each party’s representations and warranties (subject to customary materiality qualifiers) and (b) each party’s compliance with its obligations and covenants contained in the Merger Agreement (including covenants that may limit, restrict or prohibit PHI and its subsidiaries from taking specified actions during the period between the date of the Merger Agreement and the closing of the Merger or the termination of the Merger Agreement). In addition, the obligations of Exelon and Merger Sub to consummate the Merger are subject to the required regulatory approvals not imposing terms, conditions, obligations or commitments, individually or in the aggregate, that constitute a burdensome condition (as defined in the Merger Agreement). For additional discussion, see Note (7), “Regulatory Matters – Merger Approval Proceedings.” On September 23, 2014, the stockholders of PHI approved the Merger, on October 7, 2014, the VSCC approved the Merger, and on November 20, 2014, FERC approved the Merger. In addition, the transfer of control of certain communications licenses held by certain of PHI’s subsidiaries has been approved by the FCC. The NJBPU approved the Merger on February 11, 2015 and, on October 15, 2015, voted to extend the effectiveness of its approval until June 30, 2016. The DPSC approved the Merger on May 19, 2015. The waiting period under the HSR Act expired on December 2, 2015, which allows for the closing of the Merger at any time on or before December 1, 2016. On May 15, 2015, the MPSC approved the Merger, with conditions, including conditions that modify and supplement those originally proposed. On May 18, 2015, PHI and Exelon announced that they had committed to fulfill the modified, more stringent conditions and package of customer benefits imposed by the MPSC. In connection with these proceedings, the Maryland Office of People’s Counsel and several other parties to the Merger proceedings filed motions in the Circuit Court for Queen Anne’s County, Maryland, requesting a stay of the MPSC order. On August 7, 2015, the Circuit Court for Queen Anne’s County denied the motions for stay. On January 8, 2016, the Circuit Court affirmed the MPSC’s order in all respects. On January 20 and 22, 2016, respectively, the Maryland Office of People’s Counsel and environmental groups filed notices of appeal of the Circuit Court’s order to the Maryland Court of Special Appeals. Unless a motion to stay is filed and then granted by the court, the MPSC order will remain in effect during the appeals process. On August 27, 2015, the DCPSC issued a written order denying the application seeking approval of the Merger. On September 28, 2015, Exelon, PHI and Potomac Electric Power Company (Pepco), and certain of their respective affiliates, filed an application for reconsideration with the DCPSC requesting reconsideration of the DCPSC order related to the Merger. On October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, entered into a Nonunanimous Full Settlement Agreement and Stipulation (the DC Settlement Agreement) with the District of Columbia Government, the Office of the People’s Counsel and other parties, which DC Settlement Agreement contains commitments from Exelon and PHI above those contained in their original merger application. Also on October 6, 2015, PHI, Exelon and Merger Sub entered into a Letter Agreement (the Letter Agreement), setting forth the terms and conditions under which the parties will file with the DCPSC (a) a Motion of Joint Applicants to Reopen the Record in Formal Case No. 1119 to Allow for Consideration of the DC Settlement Agreement (the Motion to Reopen), or (b) if the Motion to Reopen is not granted, a new merger application, requesting approval of the Merger on the terms and commitments agreed to in the DC Settlement Agreement. Pursuant to the Letter Agreement, PHI and Exelon each agrees, among other things, that neither party will exercise the termination rights each may have under the Merger Agreement on or after October 29, 2015, unless: (i) the DCPSC does not, by November 20, 2015, set a procedural schedule which allows for a final order for approval of the Merger by March 4, 2016, (ii) the DCPSC sets a schedule for action which does not allow for a final order for approval of the Merger by March 4, 2016, (iii) the DCPSC fails to issue a final order approving the Merger and the DC Settlement Agreement as filed without condition or modification by March 4, 2016, (iv) the DCPSC issues a final order denying approval of the Merger or the DC Settlement Agreement or adds conditions or makes modifications to the DC Settlement Agreement, (v) the DC Settlement Agreement is terminated for any reason, or (vi) after March 4, 2016 a condition to closing of the Merger has not been satisfied or waived (other than those conditions that by their nature are to be satisfied at the closing). The Letter Agreement also provides that, subject to certain conditions, Exelon may, following receipt of all regulatory approvals consistent with the DC Settlement Agreement, delay closing of the Merger for up to 30 days to engage in capital markets transactions to raise additional funds required to consummate the Merger. On October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, filed with the DCPSC the Motion to Reopen requesting consideration of the DC Settlement Agreement and approval of the Merger on such terms and conditions set forth in the DC Settlement Agreement, without condition or modification, and to stay further proceedings on the application for reconsideration filed by the parties on September 28, 2015 and suspend the time period for reconsideration pending the DCPSC’s consideration of the DC Settlement Agreement. On October 28, 2015, the DCPSC approved the Motion to Reopen and set a procedural schedule for its review of this matter. Upon completion of the public input and evidentiary hearings, the record was closed as of December 23, 2015. Although District of Columbia law does not impose any time limit on the DCPSC’s review of the Merger, the parties requested a decision by March 4, 2016. |
Atlantic City Electric Co [Member] | |
Organization | (1) ORGANIZATION Atlantic City Electric Company (ACE) is engaged in the transmission and distribution of electricity in southern New Jersey. ACE also provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive energy supplier. Default Electricity Supply is known as Basic Generation Service in New Jersey. ACE is a wholly owned subsidiary of Conectiv, LLC (Conectiv), which is wholly owned by Pepco Holdings, Inc. (Pepco Holdings or PHI). PHI entered into an Agreement and Plan of Merger, dated April 29, 2014, as amended and restated on July 18, 2014 (the Merger Agreement), with Exelon Corporation, a Pennsylvania corporation (Exelon), and Purple Acquisition Corp., a Delaware corporation and an indirect, wholly owned subsidiary of Exelon (Merger Sub), providing for the merger of Merger Sub with and into PHI (the Merger), with PHI surviving the Merger as an indirect, wholly owned subsidiary of Exelon. Pursuant to the Merger Agreement, at the effective time of the Merger, each outstanding share of common stock, par value $0.01 per share, of PHI (other than (i) shares owned by Exelon, Merger Sub or any other direct or indirect wholly owned subsidiary of Exelon and shares owned by PHI or any direct or indirect wholly owned subsidiary of PHI, and in each case not held on behalf of third parties (but not including shares held by PHI in any rabbi trust or similar arrangement in respect of any compensation plan or arrangement) and (ii) shares that are owned by stockholders who have perfected and not withdrawn a demand for appraisal rights pursuant to Delaware law), will be canceled and converted into the right to receive $27.25 in cash, without interest. In connection with entering into the Merger Agreement, PHI entered into a Subscription Agreement, dated April 29, 2014 (the Subscription Agreement), with Exelon, pursuant to which on April 30, 2014, PHI issued to Exelon 9,000 originally issued shares of non-voting, non-convertible and non-transferable Series A preferred stock, par value $0.01 per share (the Preferred Stock), for a purchase price of $90 million. Exelon also committed pursuant to the Subscription Agreement to purchase 1,800 originally issued shares of Preferred Stock for a purchase price of $18 million at the end of each 90-day period following the date of the Subscription Agreement until the Merger closes or is terminated, up to a maximum of 18,000 shares of Preferred Stock for a maximum aggregate consideration of $180 million. In accordance with the Subscription Agreement, on each of July 29, 2014, October 27, 2014, January 26, 2015, April 27, 2015 and July 24, 2015, an additional 1,800 shares of Preferred Stock were issued by PHI to Exelon for an aggregate purchase price of $90 million. The holders of the Preferred Stock will be entitled to receive a cumulative, non-participating cash dividend of 0.1% per annum, payable quarterly, when, as and if declared by PHI’s board of directors. The proceeds from the issuance of the Preferred Stock are not subject to restrictions and are intended to serve as a prepayment of any applicable reverse termination fee payable from Exelon to PHI. The Preferred Stock will be redeemable on the terms and in the circumstances set forth in the Merger Agreement and the Subscription Agreement. The Merger Agreement provides for certain termination rights for each of PHI and Exelon, and further provides that, upon termination of the Merger Agreement under certain specified circumstances, PHI will be required to pay Exelon a termination fee of $259 million or reimburse Exelon for its expenses up to $40 million (which reimbursement of expenses shall reduce on a dollar for dollar basis any termination fee subsequently payable by PHI), provided, however, that if the Merger Agreement is terminated in connection with an acquisition proposal made under certain circumstances by a person who made an acquisition proposal between April 1, 2014 and the date of the Merger Agreement, the termination fee will be $293 million plus reimbursement of Exelon for its expenses up to $40 million (not subject to offset). In addition, if the Merger Agreement is terminated under certain circumstances due to the failure to obtain required regulatory approvals with respect to the Merger or the breach by Exelon of its obligations in respect of obtaining such regulatory approvals (a Regulatory Termination), PHI will be able to redeem any issued and outstanding Preferred Stock at par value, and in that case, Exelon will be required to pay all documented out-of-pocket expenses incurred by PHI in connection with the Merger Agreement or the transactions contemplated thereby, up to $40 million. If the Merger Agreement is terminated, other than for a Regulatory Termination, PHI will be required to redeem the Preferred Stock at the purchase price of $10,000 per share, plus any unpaid accrued and accumulated dividends thereupon. Consummation of the Merger is subject to the satisfaction or waiver of specified closing conditions, including (i) the approval of the Merger by the holders of a majority of the outstanding shares of common stock of PHI; (ii) the receipt of regulatory approvals required to consummate the Merger, including approvals from the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission (FCC), the Delaware Public Service Commission (DPSC), the District of Columbia Public Service Commission (DCPSC), the Maryland Public Service Commission (MPSC), the New Jersey Board of Public Utilities (NJBPU) and the Virginia State Corporation Commission (VSCC); (iii) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (the HSR Act); and (iv) other customary closing conditions, including (a) the accuracy of each party’s representations and warranties (subject to customary materiality qualifiers) and (b) each party’s compliance with its obligations and covenants contained in the Merger Agreement (including covenants that may limit, restrict or prohibit PHI and its subsidiaries from taking specified actions during the period between the date of the Merger Agreement and the closing of the Merger or the termination of the Merger Agreement). In addition, the obligations of Exelon and Merger Sub to consummate the Merger are subject to the required regulatory approvals not imposing terms, conditions, obligations or commitments, individually or in the aggregate, that constitute a burdensome condition (as defined in the Merger Agreement). For additional discussion, see Note (6), “Regulatory Matters – Merger Approval Proceedings.” On September 23, 2014, the stockholders of PHI approved the Merger, on October 7, 2014, the VSCC approved the Merger, and on November 20, 2014, FERC approved the Merger. In addition, the transfer of control of certain communications licenses held by certain of PHI’s subsidiaries has been approved by the FCC. The NJBPU approved the Merger on February 11, 2015 and, on October 15, 2015, voted to extend the effectiveness of its approval until June 30, 2016. The DPSC approved the Merger on May 19, 2015. The waiting period under the HSR Act expired on December 2, 2015, which allows for the closing of the Merger at any time on or before December 1, 2016. On May 15, 2015, the MPSC approved the Merger, with conditions, including conditions that modify and supplement those originally proposed. On May 18, 2015, PHI and Exelon announced that they had committed to fulfill the modified, more stringent conditions and package of customer benefits imposed by the MPSC. In connection with these proceedings, the Maryland Office of People’s Counsel and several other parties to the Merger proceedings filed motions in the Circuit Court for Queen Anne’s County, Maryland, requesting a stay of the MPSC order. On August 7, 2015, the Circuit Court for Queen Anne’s County denied the motions for stay. On January 8, 2016, the Circuit Court affirmed the MPSC’s order in all respects. On January 20 and 22, 2016, respectively, the Maryland Office of People’s Counsel and environmental groups filed notices of appeal of the Circuit Court’s order to the Maryland Court of Special Appeals. Unless a motion to stay is filed and then granted by the court, the MPSC order will remain in effect during the appeals process. On August 27, 2015, the DCPSC issued a written order denying the application seeking approval of the Merger. On September 28, 2015, Exelon, PHI and Potomac Electric Power Company (Pepco), and certain of their respective affiliates, filed an application for reconsideration with the DCPSC requesting reconsideration of the DCPSC order related to the Merger. On October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, entered into a Nonunanimous Full Settlement Agreement and Stipulation (the DC Settlement Agreement) with the District of Columbia Government, the Office of the People’s Counsel and other parties, which DC Settlement Agreement contains commitments from Exelon and PHI above those contained in their original merger application. Also on October 6, 2015, PHI, Exelon and Merger Sub entered into a Letter Agreement (the Letter Agreement), setting forth the terms and conditions under which the parties will file with the DCPSC (a) a Motion of Joint Applicants to Reopen the Record in Formal Case No. 1119 to Allow for Consideration of the DC Settlement Agreement (the Motion to Reopen), or (b) if the Motion to Reopen is not granted, a new merger application, requesting approval of the Merger on the terms and commitments agreed to in the DC Settlement Agreement. Pursuant to the Letter Agreement, PHI and Exelon each agrees, among other things, that neither party will exercise the termination rights each may have under the Merger Agreement on or after October 29, 2015, unless: (i) the DCPSC does not, by November 20, 2015, set a procedural schedule which allows for a final order for approval of the Merger by March 4, 2016, (ii) the DCPSC sets a schedule for action which does not allow for a final order for approval of the Merger by March 4, 2016, (iii) the DCPSC fails to issue a final order approving the Merger and the DC Settlement Agreement as filed without condition or modification by March 4, 2016, (iv) the DCPSC issues a final order denying approval of the Merger or the DC Settlement Agreement or adds conditions or makes modifications to the DC Settlement Agreement, (v) the DC Settlement Agreement is terminated for any reason, or (vi) after March 4, 2016 a condition to closing of the Merger has not been satisfied or waived (other than those conditions that by their nature are to be satisfied at the closing). The Letter Agreement also provides that, subject to certain conditions, Exelon may, following receipt of all regulatory approvals consistent with the DC Settlement Agreement, delay closing of the Merger for up to 30 days to engage in capital markets transactions to raise additional funds required to consummate the Merger. On October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, filed with the DCPSC the Motion to Reopen requesting consideration of the DC Settlement Agreement and approval of the Merger on such terms and conditions set forth in the DC Settlement Agreement, without condition or modification, and to stay further proceedings on the application for reconsideration filed by the parties on September 28, 2015 and suspend the time period for reconsideration pending the DCPSC’s consideration of the DC Settlement Agreement. On October 28, 2015, the DCPSC approved the Motion to Reopen and set a procedural schedule for its review of this matter. Upon completion of the public input and evidentiary hearings, the record was closed as of December 23, 2015. Although District of Columbia law does not impose any time limit on the DCPSC’s review of the Merger, the parties requested a decision by March 4, 2016. |
Significant Accounting Policies
Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2015 | |
Significant Accounting Policies | (2) SIGNIFICANT ACCOUNTING POLICIES Consolidation Policy The accompanying consolidated financial statements include the accounts of Pepco Holdings and its wholly owned subsidiaries. All material intercompany balances and transactions between subsidiaries have been eliminated. Pepco Holdings uses the equity method to report investments, corporate joint ventures, partnerships, and affiliated companies in which it holds an interest and can exercise significant influence over the operations and policies of the entity. Certain transmission and other facilities currently held are consolidated in proportion to PHI’s percentage interest in the facility. Consolidation of Variable Interest Entities PHI assesses its contractual arrangements with variable interest entities (VIEs) to determine whether it is the primary beneficiary and thereby has to consolidate the entities in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 810. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests. See Note (17), “Variable Interest Entities,” for additional information. Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the consolidated financial statements and accompanying notes. Although Pepco Holdings believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates. Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset and goodwill impairment calculations, fair value calculations for derivative instruments, pension and other postretirement benefit assumptions, the assessment of the adequacy of the allowance for uncollectible accounts, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, recognition of changes in network service transmission rates for prior service year costs, accrual of loss contingency liabilities for general litigation and auto and other liability claims, accrual of interest related to income taxes, the recognition of lease income and income tax benefits for investments in finance leases held in trust associated with PHI’s former cross-border energy lease investments (see Note (20), “Discontinued Operations – Cross-Border Energy Lease Investments”), and income tax provisions and reserves. Additionally, PHI is subject to legal, regulatory and other proceedings and claims that arise in the ordinary course of its business. PHI records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable. Revenue Recognition Regulated Revenue Power Delivery recognizes revenue upon distribution of electricity and natural gas to its customers, including unbilled revenue for services rendered but not yet billed. PHI’s unbilled revenue was $139 million and $172 million as of December 31, 2015 and 2014, respectively, and these amounts are included in Accounts receivable. PHI’s utility subsidiaries calculate unbilled revenue using an output-based methodology. This methodology is based on the supply of electricity or natural gas intended for distribution to customers. The unbilled revenue process requires management to make assumptions and judgments about input factors such as customer sales mix, temperature and estimated line losses (estimates of electricity and natural gas expected to be lost in the process of its transmission and distribution to customers). The assumptions and judgments are inherently uncertain and susceptible to change from period to period, and if the actual results differ from the projected results, the impact could be material. Taxes related to the consumption of electricity and natural gas by the utility customers, such as fuel, energy, or other similar taxes, are components of the tariff rates charged by PHI’s utility subsidiaries and, as such, are billed to customers and recorded in Operating revenue. Accruals for the remittance of these taxes are recorded in Other taxes. Pepco Energy Services Revenue Revenue for Pepco Energy Services’ energy savings performance construction business and certain construction contracts in its underground transmission and distribution business is recognized using the percentage-of-completion method which recognizes revenue as work is completed and costs are incurred on its contracts. Under this method, Pepco Energy Services recognizes these contractual revenues based on the percentage of incurred costs relative to the estimated costs to complete a contract. Revenues from its operation and maintenance activities and measurement and verification activities in its energy savings business and certain construction contracts in its underground transmission and distribution business are recognized when earned. Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions Taxes included in PHI’s gross revenues were $322 million, $321 million and $346 million for the years ended December 31, 2015, 2014 and 2013, respectively. Accounting for Derivatives PHI and its subsidiaries may use derivative instruments primarily to manage risk associated with commodity prices and interest rates. Risk management policies are determined by PHI’s Corporate Risk Management Committee (CRMC). The CRMC monitors interest rate fluctuation, commodity price fluctuation and credit risk exposure, and sets risk management policies that establish limits on unhedged risk. PHI accounts for its derivative activities in accordance with FASB guidance on derivatives and hedging. Derivatives are recorded on the consolidated balance sheets as Derivative assets or Derivative liabilities and measured at fair value. Changes in the fair value of derivatives held by DPL that do not qualify for hedge accounting or are not designated as hedges are presented on the consolidated statements of income (loss) as Fuel and purchased energy expense or Operating revenue, respectively. Changes in the fair value of derivatives held by DPL are deferred as regulatory assets or liabilities under the accounting guidance for regulated operations. The gain or loss on a derivative that qualifies as a cash flow hedge of an exposure to variable cash flows of a forecasted transaction is initially recorded in accumulated other comprehensive loss (AOCL) (a separate component of equity) to the extent that the hedge is effective and is subsequently reclassified into earnings, in the same category as the item being hedged, when the gain or loss from the forecasted transaction occurs. If it is probable that a forecasted transaction will not occur, the deferred gain or loss in AOCL is immediately reclassified to earnings. Gains or losses related to any ineffective portion of cash flow hedges are also recognized in earnings immediately. Changes in the fair value of derivatives designated as fair value hedges, as well as changes in the fair value of the hedged asset, liability or firm commitment, are recorded in the consolidated statements of income (loss). The impact of derivatives that are marked to market through current earnings, the ineffective portion of cash flow hedges, and the portion of fair value hedges that flows to current earnings are presented on a net basis in the consolidated statements of income (loss) as Operating revenue or as Fuel and purchased energy expense. When a hedging gain or loss is realized, it is presented on a net basis in the same line item as the underlying item being hedged. Unrealized derivative gains and losses are presented gross on the consolidated balance sheets except where contractual netting agreements are in place with individual counterparties. The fair value of derivatives is determined using quoted exchange prices where available. For instruments that are not traded on an exchange, pricing services and external broker quotes may also be used to determine fair value. For some custom and complex instruments, internal models use market-based information when external broker quotes are not available. For certain long-dated instruments, broker or exchange data are extrapolated, or capacity prices are forecasted, for future periods where information is limited. Models are also used to estimate volumes for certain transactions. PHI may enter into master netting arrangements to mitigate credit risk related to its derivatives. Under FASB guidance on offsetting of balance sheet accounts (ASC 210-20), amounts recognized for derivative assets and liabilities and the fair value amounts recognized for any related collateral positions executed with the same counterparty under such master netting agreements are offset. See Note (14), “Derivative Instruments and Hedging Activities,” for more information about the types of derivatives employed by PHI, the components of any unrealized and realized gains and losses and Note (15), “Fair Value Disclosures,” for the methodologies used to value them. Stock-Based Compensation PHI recognizes compensation expense for stock-based awards, modifications or cancellations based on the grant-date fair value. Compensation expense is recognized over the requisite service period. A deferred tax asset and deferred tax benefit are also recognized concurrently with compensation expense for the tax effect of the deduction of stock options, restricted stock and restricted stock unit awards, which are deductible only upon exercise and/or vesting. Historically, PHI’s compensation awards had included both time-based restricted stock awards that vest over a three-year service period and performance-based restricted stock and restricted stock units that were earned based on performance over a three-year period. Beginning in 2011, stock-based compensation awards have been granted primarily in the form of restricted stock units. Since May 2012, the Board of Directors have been granted an annual time-based restricted stock unit award that vests over one year as part of their compensation. The compensation expense associated with these awards is calculated based on the estimated fair value of the awards at the grant date and is recognized over the service or performance period. PHI estimates the fair value of performance-based restricted stock unit awards using the Monte Carlo valuation model. These awards include performance conditions based upon PHI’s total stockholder return (TSR) versus a select group of peer companies over a three-year period. The effect of market conditions is considered in determining the awards’ fair value. This model values the specific features of employee share-based awards, including market-based performance conditions. PHI’s current policy is to issue new shares to satisfy vested awards of restricted stock units. Income Taxes PHI and the majority of its subsidiaries file a consolidated federal income tax return. Federal income taxes are allocated among PHI and the subsidiaries included in its consolidated group pursuant to a written tax sharing agreement, which was approved by the Securities and Exchange Commission (SEC) in 2002 in connection with the establishment of PHI as a public utility holding company. Under this tax sharing agreement, PHI’s consolidated federal income tax liability is allocated based upon PHI’s and its subsidiaries’ separate taxable income or loss amounts. The consolidated financial statements include current and deferred income taxes. Current income taxes represent the amount of tax expected to be reported on PHI’s and its subsidiaries’ federal and state income tax returns. Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement basis and tax basis of existing assets and liabilities, and they are measured using presently enacted tax rates. See Note (11), “Income Taxes,” for a listing of primary deferred tax assets and liabilities. The portions of Pepco’s, DPL’s and ACE’s deferred tax liabilities applicable to their utility operations that have not been recovered from utility customers represent income taxes recoverable in the future and are included in Regulatory Assets on the consolidated balance sheets. See Note (7), “Regulatory Matters – Regulatory Assets and Regulatory Liabilities,” for additional information. PHI recognizes interest on underpayments and overpayments of income taxes, interest on uncertain tax positions and tax-related penalties in income tax expense. Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes. Investment tax credits are amortized to income over the useful lives of the related property. Cash and Cash Equivalents Cash and cash equivalents include cash on hand, cash invested in money market funds and commercial paper held with original maturities of three months or less. Restricted Cash Equivalents The Restricted cash equivalents included in Current assets and the Restricted cash equivalents included in Other assets consist of (i) cash held as collateral that is restricted from use for general corporate purposes and (ii) cash equivalents that are specifically segregated based on management’s intent to use such cash equivalents for a particular purpose. The classification as current or non-current conforms to the classification of the related liabilities. Accounts Receivable and Allowance for Uncollectible Accounts PHI’s Accounts receivable balances primarily consist of customer accounts receivable arising from the sale of goods and services to customers within PHI’s service territories, other accounts receivable, and accrued unbilled revenue. Accrued unbilled revenue represents revenue earned in the current period but not billed to the customer until a future date (usually within one month after the receivable is recorded). PHI maintains an allowance for uncollectible accounts and changes in the allowance are recorded as an adjustment to Other operation and maintenance expense in the consolidated statements of income (loss). PHI determines the amount of the allowance based on specific identification of material amounts at risk by customer and maintains a reserve based on its historical collection experience. The adequacy of this allowance is assessed on a quarterly basis by evaluating all known factors, such as the aging of the receivables, historical collection experience, the economic and competitive environment and changes in the creditworthiness of its customers. Accounts receivable are written off in the period in which the receivable is deemed uncollectible and collection efforts have been exhausted. Recoveries of Accounts receivable previously written off are recorded when received. Although PHI believes its allowance is adequate, it cannot anticipate with any certainty the changes in the financial condition of its customers. As a result, PHI records adjustments to the allowance for uncollectible accounts in the period in which the new information that requires an adjustment to the reserve becomes known. Inventories PHI utilizes the weighted average cost method of accounting for inventory items. Under this method, an average price is determined for the quantity of units acquired at each price level and is applied to the ending quantity to calculate the total ending inventory balance. Materials and supplies are recorded in Inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed. The cost of natural gas, including transportation costs, is included in Inventory when purchased and charged to Fuel and Purchased Energy expense when used. Goodwill Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired at the acquisition date. PHI tests its goodwill for impairment annually as of November 1 and whenever an event occurs or circumstances change in the interim that would more likely than not (that is, a greater than 50% chance) reduce the estimated fair value of a reporting unit below the carrying amount of its net assets. Factors that may result in an interim impairment test include, but are not limited to: a change in the identified reporting units; an adverse change in business conditions; a protracted decline in PHI’s stock price causing market capitalization to fall significantly below book value; an adverse regulatory action; or an impairment of long-lived assets in the reporting unit. PHI performed its most recent annual impairment test as of November 1, 2015, and its goodwill was not impaired as described in Note (6), “Goodwill.” Regulatory Assets and Regulatory Liabilities The operations of Pepco are regulated by the DCPSC and the MPSC. The operations of DPL are regulated by the DPSC and the MPSC. DPL’s interstate transportation and wholesale sale of natural gas are regulated by FERC. The operations of ACE are regulated by the NJBPU. The transmission of electricity by Pepco, DPL and ACE is regulated by FERC. The FASB guidance on regulated operations (ASC 980) applies to Power Delivery. It allows regulated entities, in appropriate circumstances, to defer the income statement impact of certain costs that are expected to be recovered in future rates through the establishment of regulatory assets and defer certain revenues that are expected to be refunded to customers through the establishment of regulatory liabilities. Management’s assessment of the probability of recovery of regulatory assets requires judgment and interpretation of laws, regulatory commission orders and other factors. If management subsequently determines, based on changes in facts or circumstances, that a regulatory asset is not probable of recovery, then the regulatory asset would be eliminated through a charge to earnings. Effective June 2007, the MPSC approved a bill stabilization adjustment (BSA) mechanism for retail customers of Pepco and DPL. Effective November 2009, the DCPSC approved a BSA for Pepco’s retail customers. For customers to whom the BSA applies, Pepco and DPL recognize distribution revenue based on an approved distribution charge per customer. From a revenue recognition standpoint, the BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during that period. Pursuant to this mechanism, Pepco and DPL recognize either (i) a positive adjustment equal to the amount by which revenue from Maryland and the District of Columbia retail distribution sales falls short of the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer, or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer (a Revenue Decoupling Adjustment). A net positive Revenue Decoupling Adjustment is recorded as a regulatory asset and a net negative Revenue Decoupling Adjustment is recorded as a regulatory liability. Leasing Activities Pepco Holdings’ lease transactions include plant, office space, equipment, software, vehicles and elements of power purchase agreements (PPAs). In accordance with FASB guidance on leases (ASC 840), these leases are classified as either leveraged leases, operating leases or capital leases. Leveraged Leases Income from investments in leveraged lease transactions, in which PHI was an equity participant, was accounted for using the financing method. In accordance with the financing method, investments in leased property were recorded as a receivable from the lessee to be recovered through the collection of future rentals. Income was recognized over the life of the lease at a constant rate of return on the positive net investment. Each quarter, PHI reviewed the carrying value of each lease, which included a review of the underlying financial assumptions, the timing and collectibility of cash flows, and the credit quality of the lessee. Changes to the underlying assumptions, if any, were accounted for in accordance with FASB guidance on leases and reflected in the carrying value of the lease effective for the quarter within which they occurred. Operating Leases An operating lease in which PHI or a subsidiary is the lessee generally results in a level income statement charge over the term of the lease, reflecting the rental payments required by the lease agreement. If rental payments are not made on a straight-line basis, PHI’s policy is to recognize rent expense on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed. Capital Leases For ratemaking purposes, capital leases in which PHI or a subsidiary is the lessee are treated as operating leases; therefore, in accordance with FASB guidance on regulated operations (ASC 980), the amortization of the leased asset is based on the recovery of rental payments through customer rates. Investments in equipment under capital leases are stated at cost, less accumulated depreciation. Depreciation is recorded on a straight-line basis over the equipment’s estimated useful life. Arrangements Containing a Lease PPAs are deemed to contain a lease if the arrangement conveys the right to control the use of property, plant or equipment. If so, PHI determines the appropriate lease accounting classification. Property, Plant and Equipment Property, plant and equipment is recorded at original cost, including labor, materials, asset retirement costs and other direct and indirect costs including capitalized interest. The carrying value of Property, plant and equipment is evaluated for impairment whenever circumstances indicate the carrying value of those assets may not be recoverable. Upon retirement, the cost of regulated property, net of salvage, is charged to Accumulated depreciation. For non-regulated property, the cost and accumulated depreciation of the property, plant and equipment retired or otherwise disposed of are removed from the related accounts and included in the determination of any gain or loss on disposition. The annual provision for depreciation on electric and natural gas property, plant and equipment is computed on a straight-line basis using composite rates by classes of depreciable property. Non-operating and other property is generally depreciated on a straight-line basis over the useful lives of the assets. The table below provides system-wide composite annual depreciation rates for the years ended December 31, 2015, 2014 and 2013. Transmission and 2015 2014 2013 2015 2014 2013 Pepco 2.3 % 2.3 % 2.2 % — — — DPL 2.6 % 2.6 % 2.6 % — — — ACE 2.6 % 2.6 % 2.8 % — — — Pepco Energy Services — — — 0.6 % 1.2 % 0.4 % In 2010, subsidiaries of PHI received awards from the U.S. Department of Energy (DOE) under the American Recovery and Reinvestment Act of 2009. Pepco was awarded $149 million from DOE to fund a portion of the costs incurred for the implementation of an advanced metering infrastructure (AMI) system (a system that collects, measures and analyzes energy usage data from advanced digital meters known as smart meters), direct load control, distribution automation and communications infrastructure in its Maryland and District of Columbia service territories. ACE was awarded $19 million from DOE to fund a portion of the costs incurred for the implementation of direct load control, distribution automation and communications infrastructure in its New Jersey service territory. PHI elected to recognize the award proceeds as a reduction in the carrying value of the assets acquired rather than grant income over the service period. Long-Lived Asset Impairment Evaluation PHI evaluates long-lived assets to be held and used, such as generating property and equipment, and real estate, for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Examples of such events or changes include a significant decrease in the market price of a long-lived asset or a significant adverse change in the manner in which an asset is being used or its physical condition. A long-lived asset to be held and used is written down to its estimated fair value if the expected future undiscounted cash flow from the asset is less than its carrying value. For long-lived assets held for sale, an impairment loss is recognized to the extent that the asset’s carrying value exceeds its estimated fair value including costs to sell. Capitalized Interest and Allowance for Funds Used During Construction In accordance with FASB guidance on regulated operations (ASC 980), PHI’s utility subsidiaries may capitalize the capital costs of financing the construction of plant and equipment as allowance for funds used during construction (AFUDC). This results in the debt portion of AFUDC being recorded as a reduction of Interest expense and the equity portion of AFUDC being recorded as an increase to Other income in the accompanying consolidated statements of income (loss). Pepco Holdings recorded AFUDC for borrowed funds of $8 million, $7 million and $7 million for the years ended December 31, 2015, 2014 and 2013, respectively. Pepco Holdings recorded amounts for the equity component of AFUDC of $14 million, $13 million and $11 million for the years ended December 31, 2015, 2014 and 2013, respectively. Amortization of Debt Issuance and Reacquisition Costs Pepco Holdings defers and amortizes debt issuance costs and long-term debt premiums and discounts over the lives of the respective debt issuances. When PHI utility subsidiaries refinance existing debt or redeem existing debt, any unamortized premiums, discounts and debt issuance costs, as well as debt redemption costs, are classified as regulatory assets and are amortized over the life of the original or new issue. Asset Removal Costs In accordance with FASB guidance on regulated operations (ASC 980), asset removal costs are recorded by PHI utility subsidiaries as Regulatory liabilities. At December 31, 2015 and 2014, $211 million and $250 million, respectively, of asset removal costs are included in Regulatory liabilities in the accompanying consolidated balance sheets. Pension and Postretirement Benefit Plans PHI sponsors a non-contributory, defined benefit pension plan that covers substantially all employees of Pepco, DPL, ACE and certain employees of other PHI subsidiaries (the PHI Retirement Plan). PHI also provides supplemental retirement benefits to certain eligible executives and key employees through nonqualified retirement plans and provides certain postretirement health care and life insurance benefits for eligible retired employees. Most employees hired after January 1, 2005 will not have retiree health care coverage. Net periodic benefit cost is included in Other operation and maintenance expense, net of the portion of the net periodic benefit cost capitalized as part of the cost of labor for internal construction projects. After intercompany allocations, the three utility subsidiaries are responsible for substantially all of the total PHI net periodic benefit cost. PHI accounts for the PHI Retirement Plan, the nonqualified retirement plans, and the retirement health care and life insurance benefit plans in accordance with FASB guidance on retirement benefits (ASC 715). See Note (9), “Pension and Other Postretirement Benefits,” for additional information. Reclassifications Certain prior period amounts have been reclassified in order to conform to the current period presentation. |
Potomac Electric Power Co [Member] | |
Significant Accounting Policies | (2) SIGNIFICANT ACCOUNTING POLICIES Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the financial statements and accompanying notes. Although Pepco believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates. Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset impairment calculations, pension and other postretirement benefits assumptions, the assessment of the adequacy of the allowance for uncollectible accounts, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, recognition of changes in network service transmission rates for prior service year costs, accrual of loss contingency liabilities for general litigation and auto and other liability claims and income tax provisions and reserves. Additionally, Pepco is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. Pepco records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable. Revenue Recognition Pepco recognizes revenue upon distribution of electricity to its customers, including unbilled revenue for services rendered, but not yet billed. Pepco’s unbilled revenue was $76 million and $77 million as of December 31, 2015 and 2014, respectively, and these amounts are included in Accounts receivable. Pepco calculates unbilled revenue using an output-based methodology. This methodology is based on the supply of electricity intended for distribution to customers. The unbilled revenue process requires management to make assumptions and judgments about input factors such as customer sales mix, temperature, and estimated line losses (estimates of electricity expected to be lost in the process of its transmission and distribution to customers). The assumptions and judgments are inherently uncertain and susceptible to change from period to period, and if actual results differ from projected results, the impact could be material. Taxes related to the consumption of electricity by Pepco’s customers, such as fuel, energy, or other similar taxes, are components of Pepco’s tariffs and, as such, are billed to customers and recorded in Operating revenue. Accruals for the remittance of these taxes by Pepco are recorded in Other taxes. Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions Taxes included in Pepco’s gross revenues were $304 million, $304 million and $318 million for the years ended December 31, 2015, 2014 and 2013, respectively. Long-Lived Assets Impairment Evaluation Pepco evaluates certain long-lived assets to be held and used (for example, equipment and real estate) for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Examples of such events or changes include a significant decrease in the market price of a long-lived asset or a significant adverse change in the manner in which an asset is being used or its physical condition. A long-lived asset to be held and used is written down to its estimated fair value if the expected future undiscounted cash flow from the asset is less than its carrying value. For long-lived assets that can be classified as assets to be disposed of by sale, an impairment loss is recognized to the extent that the asset’s carrying value exceeds its estimated fair value including costs to sell. Income Taxes Pepco, as a direct subsidiary of Pepco Holdings, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to Pepco based upon the taxable income or loss amounts, determined on a separate return basis. The financial statements include current and deferred income taxes. Current income taxes represent the amount of tax expected to be reported on Pepco’s state income tax returns and the amount of federal income tax allocated from Pepco Holdings. Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement basis and tax basis of existing assets and liabilities and they are measured using presently enacted tax rates. The portion of Pepco’s deferred tax liability applicable to its utility operations that has not been recovered from utility customers represents income taxes recoverable in the future and is included in Regulatory assets on the balance sheets. See Note (6), “Regulatory Matters,” for additional information. Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes. Pepco recognizes interest on underpayments and overpayments of income taxes, interest on uncertain tax positions, and tax-related penalties in income tax expense. Investment tax credits are being amortized to income over the useful lives of the related property. Cash and Cash Equivalents Cash and cash equivalents include cash on hand, cash invested in money market funds and commercial paper held with original maturities of three months or less. Additionally, deposits in PHI’s money pool, which Pepco and certain other PHI subsidiaries use to manage short-term cash management requirements, are considered cash equivalents. Deposits in the money pool are guaranteed by PHI. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the needs of its participants, which may require PHI to borrow funds for deposit from external sources. Restricted Cash Equivalents The Restricted cash equivalents included in Current assets consist of (i) cash held as collateral that is restricted from use for general corporate purposes and (ii) cash equivalents that are specifically segregated based on management’s intent to use such cash equivalents for a particular purpose. The classification as current conforms to the classification of the related liabilities. Accounts Receivable and Allowance for Uncollectible Accounts Pepco’s Accounts receivable balance primarily consists of customer accounts receivable arising from the sale of goods and services to customers within its service territory, other accounts receivable, and accrued unbilled revenue. Accrued unbilled revenue represents revenue earned in the current period but not billed to the customer until a future date (usually within one month after the receivable is recorded). Pepco maintains an allowance for uncollectible accounts and changes in the allowance are recorded as an adjustment to Other operation and maintenance expense in the statements of income. Pepco determines the amount of the allowance based on specific identification of material amounts at risk by customer and maintains a reserve based on its historical collection experience. The adequacy of this allowance is assessed on a quarterly basis by evaluating all known factors such as the aging of the receivables, historical collection experience, the economic and competitive environment and changes in the creditworthiness of its customers. Accounts receivable are written off in the period in which the receivable is deemed uncollectible and collection efforts have been exhausted. Recoveries of Accounts receivable previously written off are recorded when received. Although Pepco believes its allowance is adequate, it cannot anticipate with any certainty the changes in the financial condition of its customers. As a result, Pepco records adjustments to the allowance for uncollectible accounts in the period in which the new information that requires an adjustment to the reserve becomes known. Inventories Included in Inventories are transmission and distribution materials and supplies. Pepco utilizes the weighted average cost method of accounting for inventory items. Under this method, an average price is determined for the quantity of units acquired at each price level and is applied to the ending quantity to calculate the total ending inventory balance. Materials and supplies are recorded in Inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed. Regulatory Assets and Regulatory Liabilities Pepco is regulated by the MPSC and the DCPSC. The transmission of electricity by Pepco is regulated by FERC. Based on the regulatory framework in which it has operated, Pepco has historically applied, and in connection with its transmission and distribution business continues to apply, the Financial Accounting Standards Board (FASB) guidance on regulated operations (Accounting Standards Codification (ASC) 980). The guidance allows regulated entities, in appropriate circumstances, to defer the income statement impact of certain costs that are expected to be recovered in future rates through the establishment of regulatory assets and defer certain revenues that are expected to be refunded to customers through the establishment of regulatory liabilities. Management’s assessment of the probability of recovery of regulatory assets requires judgment and interpretation of laws, regulatory commission orders and other factors. If management subsequently determines, based on changes in facts or circumstances, that a regulatory asset is not probable of recovery, the regulatory asset would be eliminated through a charge to earnings. Effective June 2007, the MPSC approved a bill stabilization adjustment (BSA) mechanism for retail customers. Effective November 2009, the DCPSC approved a BSA for retail customers. For customers to whom the BSA applies, Pepco recognizes distribution revenue based on an approved distribution charge per customer. From a revenue recognition standpoint, the BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during that period. Pursuant to this mechanism, Pepco recognizes either (i) a positive adjustment equal to the amount by which revenue from Maryland and the District of Columbia retail distribution sales falls short of the revenue that Pepco is entitled to earn based on the approved distribution charge per customer, or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco is entitled to earn based on the approved distribution charge per customer (a Revenue Decoupling Adjustment). A net positive Revenue Decoupling Adjustment is recorded as a regulatory asset and a net negative Revenue Decoupling Adjustment is recorded as a regulatory liability. Investment in Trust Represents assets held in a trust for the benefit of participants in the Pepco Owned Life Insurance plan. Property, Plant and Equipment Property, plant and equipment is recorded at original cost, including labor, materials, asset retirement costs and other direct and indirect costs including capitalized interest. The carrying value of Property, plant and equipment is evaluated for impairment whenever circumstances indicate that the carrying value of those assets may not be recoverable. Upon retirement, the cost of regulated property, net of salvage, is charged to Accumulated depreciation. For additional information regarding the treatment of asset removal obligations, see the “Asset Removal Costs” section included in this Note. The annual provision for depreciation on electric property, plant and equipment is computed on a straight-line basis using composite rates by classes of depreciable property. Non-operating and other property is generally depreciated on a straight-line basis over the useful lives of the assets. The system-wide composite annual depreciation rates for the years ended December 31, 2015, 2014 and 2013 for Pepco’s property were approximately 2.3%, 2.3% and 2.2%, respectively. Capitalized Interest and Allowance for Funds Used During Construction In accordance with FASB guidance on regulated operations (ASC 980), utilities may capitalize the capital costs of financing the construction of plant and equipment as allowance for funds used during construction (AFUDC). This results in the debt portion of AFUDC being recorded as a reduction of Interest expense and the equity portion of AFUDC being recorded as an increase to Other income in the accompanying statements of income. Pepco recorded AFUDC for borrowed funds of $6 million, $5 million and $5 million for the years ended December 31, 2015, 2014 and 2013, respectively. Pepco recorded amounts for the equity component of AFUDC of $12 million, $10 million and $9 million for the years ended December 31, 2015, 2014 and 2013, respectively. Leasing Activities Pepco’s lease transactions include office space, equipment, software and vehicles. In accordance with FASB guidance on leases (ASC 840), these leases are classified as either operating leases or capital leases. Operating Leases An operating lease in which Pepco is the lessee generally results in a level income statement charge over the term of the lease, reflecting the rental payments required by the lease agreement. If rental payments are not made on a straight-line basis, Pepco’s policy is to recognize rent expense on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed. Capital Leases For ratemaking purposes, capital leases in which Pepco is the lessee are treated as operating leases; therefore, in accordance with FASB guidance on regulated operations (ASC 980), the amortization of the leased asset is based on the recovery of rental payments through customer rates. Investments in equipment under capital leases are stated at cost, less accumulated depreciation. Depreciation is recorded on a straight-line basis over the equipment’s estimated useful life. Amortization of Debt Issuance and Reacquisition Costs Pepco defers and amortizes debt issuance costs and long-term debt premiums and discounts over the lives of the respective debt issuances. When refinancing or redeeming existing debt, any unamortized premiums, discounts and debt issuance costs, as well as debt redemption costs, are classified as regulatory assets and are amortized generally over the life of the new issue. Asset Removal Costs In accordance with FASB guidance on regulated operations (ASC 980), asset removal costs are recorded as regulatory liabilities. At December 31, 2015 and 2014, $58 million and $84 million, respectively, of asset removal costs are included in Regulatory liabilities in the accompanying balance sheets. Pension and Postretirement Benefit Plans Pepco Holdings sponsors a non-contributory, defined benefit pension plan that covers substantially all employees of Pepco and certain employees of other Pepco Holdings subsidiaries (the PHI Retirement Plan). Pepco Holdings also provides supplemental retirement benefits to certain eligible executives and key employees through nonqualified retirement plans and provides certain postretirement health care and life insurance benefits for eligible retired employees. The PHI Retirement Plan is accounted for in accordance with FASB guidance on retirement benefits (ASC 715). Dividend Restrictions All of Pepco’s shares of outstanding common stock are held by PHI, its parent company. In addition to its future financial performance, the ability of Pepco to pay dividends to its parent company is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends, and (ii) the prior rights of holders of future preferred stock, if any, and existing and future mortgage bonds and other long-term debt issued by Pepco and any other restrictions imposed in connection with the incurrence of liabilities. Pepco has no shares of preferred stock outstanding. Pepco had approximately $1,118 million and $1,077 million of retained earnings available for payment of common stock dividends at December 31, 2015 and 2014, respectively. These amounts represent the total retained earnings balances at those dates. Reclassifications Certain prior period amounts have been reclassified in order to conform to the current period presentation. |
Delmarva Power & Light Co/De [Member] | |
Significant Accounting Policies | (2) SIGNIFICANT ACCOUNTING POLICIES Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the financial statements and accompanying notes. Although DPL believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates. Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset and goodwill impairment calculations, fair value calculations for derivative instruments, pension and other postretirement benefits assumptions, the assessment of the adequacy of the allowance for uncollectible accounts, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, recognition of changes in network service transmission rates for prior service year costs, accrual of loss contingency liabilities for general litigation and auto and other liability claims, and income tax provisions and reserves. Additionally, DPL is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. DPL records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable. Revenue Recognition DPL recognizes revenue upon distribution of electricity and natural gas to its customers, including unbilled revenue for services rendered, but not yet billed. DPL’s unbilled revenue was $37 million and $63 million as of December 31, 2015 and 2014, respectively, and these amounts are included in Accounts receivable. DPL calculates unbilled revenue using an output-based methodology. This methodology is based on the supply of electricity or natural gas intended for distribution to customers. The unbilled revenue process requires management to make assumptions and judgments about input factors such as customer sales mix, temperature, and estimated line losses (estimates of electricity and natural gas expected to be lost in the process of its transmission and distribution to customers). The assumptions and judgments are inherently uncertain and susceptible to change from period to period, and if the actual results differ from the projected results, the impact could be material. Revenue from non-regulated electricity and natural gas sales is included in Electric revenue and Natural gas revenue, respectively. Taxes related to the consumption of electricity and natural gas by DPL’s customers, such as fuel, energy, or other similar taxes, are components of DPL’s tariffs and, as such, are billed to customers and recorded in Operating revenue. Accruals for the remittance of these taxes by DPL are recorded in Other taxes. Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions Taxes included in DPL’s gross revenues were $18 million, $16 million and $17 million for the years ended December 31, 2015, 2014 and 2013, respectively. Accounting for Derivatives DPL uses derivative instruments primarily to reduce natural gas commodity price volatility and to limit its customers’ exposure to natural gas price fluctuations under a hedging program approved by the DPSC. Derivatives are recorded in the balance sheets as Derivative assets or Derivative liabilities and measured at fair value. DPL enters physical natural gas contracts as part of the hedging program that qualify as normal purchases or normal sales, which are not required to be recorded in the financial statements until settled. DPL’s capacity contracts are not classified as derivatives. Changes in the fair value of derivatives that are not designated as cash flow hedges are reflected in income. All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all gains and losses related to hedging activities, are fully recoverable through the fuel adjustment clause approved by the DPSC, and are deferred under Financial Accounting Standards Board (FASB) guidance on regulated operations (Accounting Standards Codification (ASC) 980) until recovered. Long-Lived Assets Impairment Evaluation DPL evaluates certain long-lived assets to be held and used (for example, equipment and real estate) for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Examples of such events or changes include a significant decrease in the market price of a long-lived asset or a significant adverse change in the manner in which an asset is being used or its physical condition. A long-lived asset to be held and used is written down to its estimated fair value if the expected future undiscounted cash flow from the asset is less than its carrying value. For long-lived assets that can be classified as assets to be disposed of by sale, an impairment loss is recognized to the extent that the assets’ carrying value exceeds its estimated fair value including costs to sell. Income Taxes DPL, as an indirect subsidiary of Pepco Holdings, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to DPL based upon the taxable income or loss amounts, determined on a separate return basis. The accompanying financial statements include current and deferred income taxes. Current income taxes represent the amount of tax expected to be reported on DPL’s state income tax returns and the amount of federal income tax allocated from Pepco Holdings. Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement basis and tax basis of existing assets and liabilities, and they are measured using presently enacted tax rates. The portion of DPL’s deferred tax liability applicable to its utility operations that has not been recovered from utility customers represents income taxes recoverable in the future and is included in Regulatory assets on the accompanying balance sheets. See Note (7), “Regulatory Matters,” for additional information. Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes. DPL recognizes interest on underpayments and overpayments of income taxes, interest on uncertain tax positions, and tax-related penalties in income tax expense. Investment tax credits are being amortized to income over the useful lives of the related property. Consolidation of Variable Interest Entities DPL assesses its contractual arrangements with variable interest entities (VIEs) to determine whether it is the primary beneficiary and thereby has to consolidate the entities in accordance with FASB ASC 810. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests. See Note (17), “Variable Interest Entities,” for additional information. Cash and Cash Equivalents Cash and cash equivalents include cash on hand, cash invested in money market funds and commercial paper held with original maturities of three months or less. Additionally, deposits in PHI’s money pool, which DPL and certain other PHI subsidiaries use to manage short-term cash management requirements, are considered cash equivalents. Deposits in the money pool are guaranteed by PHI. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the needs of its participants, which may require PHI to borrow funds for deposit from external sources. Accounts Receivable and Allowance for Uncollectible Accounts DPL’s Accounts receivable balance primarily consists of customer accounts receivable arising from the sale of goods and services to customers within its service territory, other accounts receivable, and accrued unbilled revenue. Accrued unbilled revenue represents revenue earned in the current period but not billed to the customer until a future date (usually within one month after the receivable is recorded). DPL maintains an allowance for uncollectible accounts and changes in the allowance are recorded as an adjustment to Other operation and maintenance expense in the accompanying statements of income. DPL determines the amount of the allowance based on specific identification of material amounts at risk by customer and maintains a reserve based on its historical collection experience. The adequacy of this allowance is assessed on a quarterly basis by evaluating all known factors such as the aging of the receivables, historical collection experience, the economic and competitive environment and changes in the creditworthiness of its customers. Accounts receivable are written off in the period in which the receivable is deemed uncollectible and collection efforts have been exhausted. Recoveries of Accounts receivable previously written off are recorded when received. Although DPL believes its allowance is adequate, it cannot anticipate with any certainty the changes in the financial condition of its customers. As a result, DPL records adjustments to the allowance for uncollectible accounts in the period in which the new information that requires an adjustment to the reserve becomes known. Inventories Included in Inventories are transmission and distribution materials and supplies and natural gas. DPL utilizes the weighted average cost method of accounting for inventory items. Under this method, an average price is determined for the quantity of units acquired at each price level and is applied to the ending quantity to calculate the total ending inventory balance. Materials and supplies are recorded in Inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed. The cost of natural gas, including transportation costs, is included in Inventory when purchased and charged to Gas purchased expense when used. Goodwill Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired at the acquisition date. DPL tests its goodwill for impairment annually as of November 1 and whenever an event occurs or circumstances change in the interim that would more likely than not (that is, a greater than 50% chance) reduce the estimated fair value of DPL below the carrying amount of its net assets. Factors that may result in an interim impairment test include, but are not limited to: a change in the identified reporting unit, an adverse change in business conditions, an adverse regulatory action, or an impairment of DPL’s long-lived assets. DPL performed its most recent annual impairment test as of November 1, 2015, and its goodwill was not impaired as described in Note (6), “Goodwill.” Regulatory Assets and Regulatory Liabilities Certain aspects of DPL’s business are subject to regulation by the DPSC and the MPSC. The transmission of electricity by DPL is regulated by FERC. DPL’s interstate transportation and wholesale sale of natural gas are regulated by FERC. Based on the regulatory framework in which it has operated, DPL has historically applied, and in connection with its transmission and distribution business continues to apply, FASB guidance on regulated operations (ASC 980). The guidance allows regulated entities, in appropriate circumstances, to defer the income statement impact of certain costs that are expected to be recovered in future rates through the establishment of regulatory assets and defer certain revenues that are expected to be refunded to customers through the establishment of regulatory liabilities. Management’s assessment of the probability of recovery of regulatory assets requires judgment and interpretation of laws, regulatory commission orders and other factors. If management subsequently determines, based on changes in facts or circumstances, that a regulatory asset is not probable of recovery, the regulatory asset would be eliminated through a charge to earnings. Effective June 2007, the MPSC approved a bill stabilization adjustment (BSA) mechanism for retail customers. For customers to whom the BSA applies, DPL recognizes distribution revenue based on an approved distribution charge per customer. From a revenue recognition standpoint, the BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during that period. Pursuant to this mechanism, DPL recognizes either (i) a positive adjustment equal to the amount by which revenue from Maryland retail distribution sales falls short of the revenue that DPL is entitled to earn based on the approved distribution charge per customer, or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that DPL is entitled to earn based on the approved distribution charge per customer (a Revenue Decoupling Adjustment). A net positive Revenue Decoupling Adjustment is recorded as a regulatory asset and a net negative Revenue Decoupling Adjustment is recorded as a regulatory liability. Property, Plant and Equipment Property, plant and equipment is recorded at original cost, including labor, materials, asset retirement costs and other direct and indirect costs including capitalized interest. The carrying value of Property, plant and equipment is evaluated for impairment whenever circumstances indicate that the carrying value of those assets may not be recoverable. Upon retirement, the cost of regulated property, net of salvage, is charged to Accumulated depreciation. For additional information regarding the treatment of asset retirement obligations, see the “Asset Removal Costs” section included in this Note. The annual provision for depreciation on electric and natural gas property, plant and equipment is computed on a straight-line basis using composite rates by classes of depreciable property. Non-operating and other property is generally depreciated on a straight-line basis over the useful lives of the assets. The system-wide composite annual depreciation rate for each of the years ended December 31, 2015, 2014 and 2013 for DPL’s property was approximately 2.6%. Capitalized Interest and Allowance for Funds Used During Construction In accordance with FASB guidance on regulated operations (ASC 980), utilities may capitalize the capital costs of financing the construction of plant and equipment as allowance for funds used during construction (AFUDC). This results in the debt portion of AFUDC being recorded as a reduction of Interest expense and the equity portion of AFUDC being recorded as an increase to Other income in the accompanying statements of income. DPL recorded AFUDC for borrowed funds of $1 million, $1 million and $2 million for the years ended December 31, 2015, 2014 and 2013, respectively. DPL recorded amounts for the equity component of AFUDC of $1 million, $2 million and $2 million for the years ended December 31, 2015, 2014 and 2013, respectively. Leasing Activities DPL’s lease transactions include plant, office space, equipment, software, vehicles and elements of power purchase agreements (PPAs). In accordance with FASB guidance on leases (ASC 840), these leases are classified as operating leases. Operating Leases An operating lease in which DPL is the lessee generally results in a level income statement charge over the term of the lease, reflecting the rental payments required by the lease agreement. If rental payments are not made on a straight-line basis, DPL’s policy is to recognize rent expense on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed. Arrangements Containing a Lease PPAs are deemed to contain a lease if the arrangement conveys the right to control the use of property, plant or equipment. If so, DPL determines the appropriate lease accounting classification. Amortization of Debt Issuance and Reacquisition Costs DPL defers and amortizes debt issuance costs and long-term debt premiums and discounts over the lives of the respective debt issuances. When refinancing or redeeming existing debt, any unamortized premiums, discounts and debt issuance costs, as well as debt redemption costs, are classified as regulatory assets and are amortized generally over the life of the original issue. Asset Removal Costs In accordance with FASB guidance on regulated operations (ASC 980), asset removal costs are recorded as regulatory liabilities. At December 31, 2015 and 2014, $153 million and $166 million, respectively, of asset removal costs are included in Regulatory liabilities in the accompanying balance sheets. Pension and Postretirement Benefit Plans Pepco Holdings sponsors a non-contributory, defined benefit pension plan that covers substantially all employees of DPL and certain employees of other Pepco Holdings subsidiaries (the PHI Retirement Plan). Pepco Holdings also provides supplemental retirement benefits to certain eligible executives and key employees through nonqualified retirement plans and provides certain postretirement health care and life insurance benefits for eligible retired employees. The PHI Retirement Plan is accounted for in accordance with FASB guidance on retirement benefits (ASC 715). Dividend Restrictions All of DPL’s shares of outstanding common stock are held by Conectiv, its parent company. In addition to its future financial performance, the ability of DPL to pay dividends to its parent company is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends, and (ii) the prior rights of holders of future preferred stock, if any, and existing and future mortgage bonds and other long-term debt issued by DPL and any other restrictions imposed in connection with the incurrence of liabilities. DPL has no shares of preferred stock outstanding. DPL had approximately $625 million and $641 million of retained earnings available for payment of common stock dividends at December 31, 2015 and 2014, respectively. These amounts represent the total retained earnings balances at those dates. Reclassifications Certain prior period amounts have been reclassified in order to conform to the current period presentation. |
Atlantic City Electric Co [Member] | |
Significant Accounting Policies | (2) SIGNIFICANT ACCOUNTING POLICIES Consolidation Policy The accompanying consolidated financial statements include the accounts of ACE and its wholly owned subsidiary Atlantic City Electric Transition Funding, LLC (ACE Funding). All intercompany balances and transactions between subsidiaries have been eliminated. ACE uses the equity method to report investments, corporate joint ventures, partnerships, and affiliated companies where it holds an interest and can exercise significant influence over the operations and policies of the entity. Certain transmission and other facilities currently held are consolidated in proportion to ACE’s percentage interest in the facility. Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the consolidated financial statements and accompanying notes. Although ACE believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates. Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset impairment calculations, fair value calculations for derivative instruments, pension and other postretirement benefits assumptions, the assessment of the adequacy of the allowance for uncollectible accounts, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, recognition of changes in network service transmission rates for prior service year costs, accrual of loss contingency liabilities for general litigation and auto and other liability claims, and income tax provisions and reserves. Additionally, ACE is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. ACE records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable. Revenue Recognition ACE recognizes revenue upon distribution of electricity to its customers, including unbilled revenue for electricity delivered but not yet billed. ACE’s unbilled revenue was $26 million and $32 million as of December 31, 2015 and 2014, respectively, and these amounts are included in Accounts receivable. ACE calculates unbilled revenue using an output-based methodology. This methodology is based on the supply of electricity intended for distribution to customers. The unbilled revenue process requires management to make assumptions and judgments about input factors such as customer sales mix, temperature, and estimated line losses (estimates of electricity expected to be lost in the process of its transmission and distribution to customers). The assumptions and judgments are inherently uncertain and susceptible to change from period to period, and if the actual results differ from the projected results, the impact could be material. Taxes related to the consumption of electricity by ACE’s customers are a component of ACE’s tariffs and, as such, are billed to customers and recorded in Operating revenue. Accruals for the remittance of these taxes by ACE are recorded in Other taxes. Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions Taxes included in ACE’s gross revenues were zero, $1 million and $11 million for the years ended December 31, 2015, 2014 and 2013, respectively. Long-Lived Asset Impairment Evaluation ACE evaluates certain long-lived assets to be held and used (for example, equipment and real estate) for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Examples of such events or changes include a significant decrease in the market price of a long-lived asset or a significant adverse change in the manner in which an asset is being used or its physical condition. A long-lived asset to be held and used is written down to its estimated fair value if the expected future undiscounted cash flow from the asset is less than its carrying value. For long-lived assets that can be classified as assets to be disposed of by sale, an impairment loss is recognized to the extent that the asset’s carrying value exceeds its estimated fair value including costs to sell. Income Taxes ACE, as an indirect subsidiary of Pepco Holdings, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to ACE based upon the taxable income or loss amounts, determined on a separate return basis. The consolidated financial statements include current and deferred income taxes. Current income taxes represent the amount of tax expected to be reported on ACE’s state income tax returns and the amount of federal income tax allocated from Pepco Holdings. Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement basis and tax basis of existing assets and liabilities, and they are measured using presently enacted tax rates. The portion of ACE’s deferred tax liability applicable to its utility operations that has not been recovered from utility customers represents income taxes recoverable in the future and is included in Regulatory assets on the consolidated balance sheets. See Note (6), “Regulatory Matters,” for additional information. Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes. ACE recognizes interest on underpayments and overpayments of income taxes, interest on uncertain tax positions, and tax-related penalties in income tax expense. Investment tax credits are being amortized to income over the useful lives of the related property. Consolidation of Variable Interest Entities ACE assesses its contractual arrangements with variable interest entities (VIEs) to determine whether it is the primary beneficiary and thereby has to consolidate the entities in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 810. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests. See Note (16), “Variable Interest Entities,” for additional information. Cash and Cash Equivalents Cash and cash equivalents include cash on hand, cash invested in money market funds and commercial paper held with original maturities of three months or less. Additionally, deposits in PHI’s money pool, which ACE and certain other PHI subsidiaries use to manage short-term cash management requirements, are considered cash equivalents. Deposits in the money pool are guaranteed by PHI. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the needs of its participants, which may require PHI to borrow funds for deposit from external sources. Restricted Cash Equivalents The Restricted cash equivalents included in Current assets and the Restricted cash equivalents included in Other assets consist of (i) cash held as collateral that is restricted from use for general corporate purposes and (ii) cash equivalents that are specifically segregated based on management’s intent to use such cash equivalents for a particular purpose. The classification as current or non-current conforms to the classification of the related liabilities. Accounts Receivable and Allowance for Uncollectible Accounts ACE’s Accounts receivable balance primarily consists of customer accounts receivable arising from the sale of goods and services to customers within its service territories, other accounts receivable, and accrued unbilled revenue. Accrued unbilled revenue represents revenue earned in the current period but not billed to the customer until a future date (usually within one month after the receivable is recorded). ACE maintains an allowance for uncollectible accounts and changes in the allowance are recorded as an adjustment to Other operation and maintenance expense in the consolidated statements of income. ACE determines the amount of the allowance based on specific identification of material amounts at risk by customer and maintains a reserve based on its historical collection experience. The adequacy of this allowance is assessed on a quarterly basis by evaluating all known factors such as the aging of the receivables, historical collection experience, the economic and competitive environment and changes in the creditworthiness of its customers. Accounts receivable are written off in the period in which the receivable is deemed uncollectible and collection efforts have been exhausted. Recoveries of Accounts receivable previously written off are recorded when received. Although ACE believes its allowance is adequate, it cannot anticipate with any certainty the changes in the financial condition of its customers. As a result, ACE records adjustments to the allowance for uncollectible accounts in the period in which the new information that requires an adjustment to the reserve becomes known. Inventories Included in inventories are transmission and distribution materials and supplies. ACE utilizes the weighted average cost method of accounting for inventory items. Under this method, an average price is determined for the quantity of units acquired at each price level and is applied to the ending quantity to calculate the total ending inventory balance. Materials and supplies are recorded in Inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed. Regulatory Assets and Regulatory Liabilities Certain aspects of ACE’s business are subject to regulation by the NJBPU. The transmission of electricity by ACE is regulated by FERC. Based on the regulatory framework in which it has operated, ACE has historically applied, and in connection with its transmission and distribution business continues to apply, FASB guidance on regulated operations (ASC 980). The guidance allows regulated entities, in appropriate circumstances, to defer the income statement impact of certain costs that are expected to be recovered in future rates through the establishment of regulatory assets and defer certain revenues that are expected to be refunded to customers through the establishment of regulatory liabilities. Management’s assessment of the probability of recovery of regulatory assets requires judgment and interpretation of laws, regulatory commission orders and other factors. If management subsequently determines, based on changes in facts or circumstances, that a regulatory asset is not probable of recovery, the regulatory asset would be eliminated through a charge to earnings. Property, Plant and Equipment Property, plant and equipment is recorded at original cost, including labor, materials, asset retirement costs and other direct and indirect costs, including capitalized interest. The carrying value of Property, plant and equipment is evaluated for impairment whenever circumstances indicate that the carrying value of those assets may not be recoverable. Upon retirement, the cost of regulated property, net of salvage, is charged to accumulated depreciation. The annual provision for depreciation on electric property, plant and equipment is computed on a straight-line basis using composite rates by classes of depreciable property. Non-operating and other property is generally depreciated on a straight-line basis over the useful lives of the assets. The system-wide composite annual depreciation rates for the years ended December 31, 2015, 2014 and 2013 for ACE’s property were approximately 2.6%, 2.6% and 2.8%, respectively. Capitalized Interest and Allowance for Funds Used During Construction In accordance with FASB guidance on regulated operations (ASC 980), utilities may capitalize the capital costs of financing the construction of plant and equipment as allowance for funds used during construction (AFUDC). This results in the debt portion of AFUDC being recorded as a reduction of Interest expense and the equity portion of AFUDC being recorded as an increase to Other income in the accompanying consolidated statements of income. ACE recorded AFUDC for borrowed funds of $1 million, $1 million and less than $1 million for the years ended December 31, 2015, 2014 and 2013, respectively. ACE recorded amounts for the equity component of AFUDC of $1 million, $1 million and less than $1 million for the years ended December 31, 2015, 2014 and 2013, respectively. Leasing Activities ACE’s lease transactions include plant, office space, equipment, software, vehicles and elements of power purchase agreements (PPAs). In accordance with FASB guidance on leases (ASC 840), these leases are classified as operating leases. Operating Leases An operating lease in which ACE is the lessee generally results in a level income statement charge over the term of the lease, reflecting the rental payments required by the lease agreement. If rental payments are not made on a straight-line basis, ACE’s policy is to recognize rent expense on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed. Arrangements Containing a Lease PPAs are deemed to contain a lease if the arrangement conveys the right to control the use of property, plant or equipment. If so, ACE determines the appropriate lease accounting classification. Amortization of Debt Issuance and Reacquisition Costs ACE defers and amortizes debt issuance costs and long-term debt premiums and discounts over the lives of the respective debt issuances. When refinancing or redeeming existing debt, any unamortized premiums, discounts and debt issuance costs, as well as debt redemption costs, are classified as regulatory assets and are amortized generally over the life of the original issue. Pension and Postretirement Benefit Plans Pepco Holdings sponsors a non-contributory, defined benefit pension plan that covers substantially all employees of ACE and certain employees of other Pepco Holdings subsidiaries (the PHI Retirement Plan). Pepco Holdings also provides supplemental retirement benefits to certain eligible executives and key employees through nonqualified retirement plans and provides certain postretirement health care and life insurance benefits for eligible retired employees. The PHI Retirement Plan is accounted for in accordance with FASB guidance on retirement benefits (ASC 715). Dividend Restrictions All of ACE’s shares of outstanding common stock are held by Conectiv, its parent company. In addition to its future financial performance, the ability of ACE to pay dividends to its parent company is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends and the regulatory requirement that ACE obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%; (ii) the prior rights of holders of future preferred stock, if any, and existing and future mortgage bonds and other long-term debt issued by ACE and any other restrictions imposed in connection with the incurrence of liabilities; and (iii) certain provisions of ACE’s charter that impose restrictions on payment of common stock dividends for the benefit of preferred stockholders. Currently, the restriction in the ACE charter does not limit its ability to pay common stock dividends. ACE had approximately $235 million and $209 million of retained earnings available for payment of common stock dividends at December 31, 2015 and 2014, respectively. These amounts represent the total retained earnings balances at those dates. Reclassifications Certain prior period amounts have been reclassified in order to conform to the current period presentation. |
Newly Adopted Accounting Standa
Newly Adopted Accounting Standards | 12 Months Ended |
Dec. 31, 2015 | |
Newly Adopted Accounting Standards | (3) NEWLY ADOPTED ACCOUNTING STANDARDS Discontinued Operations (ASC 205) In April 2014, the FASB issued new guidance on the reporting of discontinued operations that is effective for dispositions that occur after January 1, 2015. In order for dispositions to be presented as discontinued operations, the dispositions must represent a strategic shift that will have a major effect on an entity’s operations and financial results. Adoption of this guidance during the first quarter of 2015 did not have an impact on PHI’s consolidated financial statements. Business Combinations (ASC 805) In November 2014, the FASB issued new recognition and disclosure requirements related to pushdown accounting. The new recognition requirements grant an acquired entity (or its subsidiaries) the option to elect whether and when a new accounting and reporting basis (pushdown accounting) will be applied when an acquirer obtains control of the acquired entity. This election may be made by the acquired entity (or its subsidiaries) for future change-in-control events or for its most recent change-in-control event, and the acquired entity will be required to determine whether pushdown accounting will be applied in the reporting period in which the change-in-control event occurs or in a subsequent reporting period. The new required disclosures include information that enables financial statement users to evaluate the effects of pushdown accounting. Disclosures are required to be made in the period in which pushdown accounting is applied and are expected to include both qualitative and quantitative information. The new recognition and disclosure requirements became effective on a prospective basis on November 18, 2014. PHI currently anticipates it may be affected by the new guidance if its Merger with Exelon is consummated. Fair Value Measurement (ASC 820) In May 2015, the FASB issued new disclosure requirements for investment fair values. Under the new requirements, investment fair values based on net asset value (NAV) per share will continue to be disclosed, however, a level will not be assigned to those investment fair values. The new requirements are effective for PHI beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented; however, early adoption is permitted. PHI has elected to early adopt the new guidance and implement the change in accounting principle in the fourth quarter of 2015. The impact of this guidance effected the presentation of certain investments that use NAV per share as a practical expedient in Note (9), “Pension and Other Postretirement Benefits” and had no impact to Note (15), “Fair Value Disclosure,” as the financial instruments measured at fair value on a recurring basis and other financial instruments are not based on NAV. Presentation of Debt Issuance Costs (ASC 835) In April 2015, the FASB issued new guidance for the presentation of debt issuance costs on the balance sheet. Debt issuance costs are currently required to be presented on the balance sheet as assets. However, under the new requirements, these debt issuance costs will be offset against the debt to which the costs relate. The new requirements are effective for PHI beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented; however, early adoption is permitted. PHI has elected to early adopt the new guidance in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in PHI’s consolidated balance sheet as of December 31, 2014. December 31, 2014 As Filed Reclassification ASC 835 December 31, 2014 As Adjusted (millions of dollars) Other (within other assets) $ 166 $ (45 ) $ 121 Long-term debt 4,441 (44 ) 4,397 Transition bonds issued by ACE Funding 171 (1 ) 170 Balance Sheet Classification of Deferred Taxes (ASC 740) In November 2015, the FASB issued new requirements for the balance sheet classification of deferred taxes. Entities are currently required to present a current and noncurrent deferred tax balance on the balance sheet. Under the new requirements, deferred taxes will only be presented as noncurrent. The new requirements are effective for PHI beginning January 1, 2017, and may be implemented on either a prospective or retrospective basis; however, early adoption is permitted. PHI has elected to early adopt the new guidance on a retrospective basis in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in PHI’s consolidated balance sheet as of December 31, 2014. December 31, 2014 As Filed Reclassification ASC 740 December 31, 2014 As Adjusted (millions of dollars) Deferred income taxes, net (within current assets) $ 50 $ (50 ) $ — Deferred income taxes, net (within other assets) — 17 17 Other (within current liabilities) 314 (9 ) 305 Deferred income tax liabilities, net 3,266 (24 ) 3,242 |
Potomac Electric Power Co [Member] | |
Newly Adopted Accounting Standards | (3) NEWLY ADOPTED ACCOUNTING STANDARDS Business Combinations (ASC 805) In November 2014, the FASB issued new recognition and disclosure requirements related to pushdown accounting. The new recognition requirements grant an acquired entity (or its subsidiaries) the option to elect whether and when a new accounting and reporting basis (pushdown accounting) will be applied when an acquirer obtains control of the acquired entity. This election may be made by the acquired entity (or its subsidiaries) for future change-in-control events or for its most recent change-in-control event, and the acquired entity will be required to determine whether pushdown accounting will be applied in the reporting period in which the change-in-control event occurs or in a subsequent reporting period. The new required disclosures include information that enables financial statement users to evaluate the effects of pushdown accounting. Disclosures are required to be made in the period in which pushdown accounting is applied and are expected to include both qualitative and quantitative information. The new recognition and disclosure requirements became effective on a prospective basis on November 18, 2014. Presentation of Debt Issuance Costs (ASC 835) In April 2015, the FASB issued new guidance for the presentation of debt issuance costs on the balance sheet. Debt issuance costs are currently required to be presented on the balance sheet as assets. However, under the new requirements, these debt issuance costs will be offset against the debt to which the costs relate. The new requirements are effective for Pepco beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented; however, early adoption is permitted. Pepco has elected to early adopt the new guidance in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in Pepco’s balance sheet as of December 31, 2014. December 31, 2014 As Filed Reclassification December 31, 2014 As Adjusted (millions of dollars) Other (within other assets) $ 71 $ (28 ) $ 43 Long-term debt 2,124 (28 ) 2,096 Balance Sheet Classification of Deferred Taxes (ASC 740) In November 2015, the FASB issued new requirements for the balance sheet classification of deferred taxes. Entities are currently required to present a current and noncurrent deferred tax balance on the balance sheet. Under the new requirements, deferred taxes will only be presented as noncurrent. The new requirements are be effective for PHI beginning January 1, 2017, and may be implemented on either a prospective or retrospective basis; however, early adoption is permitted. PHI has elected to early adopt the new guidance on a retrospective basis in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in Pepco’s balance sheet as of December 31, 2014. December 31, 2014 Reclassification December 31, 2014 (millions of dollars) Deferred income taxes, net (within current assets) $ 14 $ (14 ) $ — Other (within current liabilities) 102 (9 ) 93 Deferred income tax liabilities, net 1,584 (5 ) 1,579 |
Delmarva Power & Light Co/De [Member] | |
Newly Adopted Accounting Standards | (3) NEWLY ADOPTED ACCOUNTING STANDARDS Business Combinations (ASC 805) In November 2014, the FASB issued new recognition and disclosure requirements related to pushdown accounting. The new recognition requirements grant an acquired entity (or its subsidiaries) the option to elect whether and when a new accounting and reporting basis (pushdown accounting) will be applied when an acquirer obtains control of the acquired entity. This election may be made by the acquired entity (or its subsidiaries) for future change-in-control events or for its most recent change-in-control event, and the acquired entity will be required to determine whether pushdown accounting will be applied in the reporting period in which the change-in-control event occurs or in a subsequent reporting period. The new required disclosures include information that enables financial statement users to evaluate the effects of pushdown accounting. Disclosures are required to be made in the period in which pushdown accounting is applied and are expected to include both qualitative and quantitative information. The new recognition and disclosure requirements became effective on a prospective basis on November 18, 2014. Presentation of Debt Issuance Costs (ASC 835) In April 2015, the FASB issued new guidance for the presentation of debt issuance costs on the balance sheet. Debt issuance costs are currently required to be presented on the balance sheet as assets. However, under the new requirements, these debt issuance costs will be offset against the debt to which the costs relate. The new requirements are effective for DPL beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented; however, early adoption is permitted. DPL has elected to early adopt the new guidance in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in DPL’s balance sheet as of December 31, 2014. December 31, 2014 As Filed Reclassification ASC 835 December 31, 2014 As Adjusted (millions of dollars) Other (within other assets) $ 12 $ (8 ) $ 4 Long-term debt 971 (8 ) 963 Balance Sheet Classification of Deferred Taxes (ASC 740) In November 2015, the FASB issued new requirements for the balance sheet classification of deferred taxes. Entities are currently required to present a current and noncurrent deferred tax balance on the balance sheet. Under the new requirements, deferred taxes will only be presented as noncurrent. The new requirements are effective for PHI beginning January 1, 2017, and may be implemented on either a prospective or retrospective basis; however, early adoption is permitted. PHI has elected to early adopt the new guidance on a retrospective basis in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in DPL’s balance sheet as of December 31, 2014. December 31, 2014 As Filed Reclassification ASC 740 December 31, 2014 As Adjusted (millions of dollars) Deferred income taxes, net (within current assets) $ 16 $ (16 ) $ — Other (within current liabilities) 42 (1 ) 41 Deferred income tax liabilities, net 893 (15 ) 878 |
Atlantic City Electric Co [Member] | |
Newly Adopted Accounting Standards | (3) NEWLY ADOPTED ACCOUNTING STANDARDS Business Combinations (ASC 805) In November 2014, the FASB issued new recognition and disclosure requirements related to pushdown accounting. The new recognition requirements grant an acquired entity (or its subsidiaries) the option to elect whether and when a new accounting and reporting basis (pushdown accounting) will be applied when an acquirer obtains control of the acquired entity. This election may be made by the acquired entity (or its subsidiaries) for future change-in-control events or for its most recent change-in-control event, and the acquired entity will be required to determine whether pushdown accounting will be applied in the reporting period in which the change-in-control event occurs or in a subsequent reporting period. The new required disclosures include information that enables financial statement users to evaluate the effects of pushdown accounting. Disclosures are required to be made in the period in which pushdown accounting is applied and are expected to include both qualitative and quantitative information. The new recognition and disclosure requirements became effective on a prospective basis on November 18, 2014. Presentation of Debt Issuance Costs (ASC 835) In April 2015, the FASB issued new guidance for the presentation of debt issuance costs on the balance sheet. Debt issuance costs are currently required to be presented on the balance sheet as assets. However, under the new requirements, these debt issuance costs will be offset against the debt to which the costs relate. The new requirements are effective for ACE beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented; however, early adoption is permitted. ACE has elected to early adopt the new guidance in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in ACE’s consolidated balance sheet as of December 31, 2014. December 31, 2014 Reclassification December 31, 2014 (millions of dollars) Other (within other assets) $ 12 $ (7 ) $ 5 Long-term debt 888 (6 ) 882 Transition bonds issued by ACE Funding 171 (1 ) 170 Balance Sheet Classification of Deferred Taxes (ASC 740) In November 2015, the FASB issued new requirements for the balance sheet classification of deferred taxes. Entities are currently required to present a current and noncurrent deferred tax balance on the balance sheet. Under the new requirements, deferred taxes will only be presented as noncurrent. The new requirements are effective for PHI beginning January 1, 2017, and may be implemented on either a prospective or retrospective basis; however, early adoption is permitted. PHI has elected to early adopt the new guidance on a retrospective basis in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in ACE’s consolidated balance sheet as of December 31, 2014. December 31, 2014 Reclassification December 31, 2014 (millions of dollars) Prepaid expenses and other $ 13 $ (10 ) $ 3 Deferred income tax liabilities, net 865 (10 ) 855 |
Recently Issued Accounting Stan
Recently Issued Accounting Standards, Not Yet Adopted | 12 Months Ended |
Dec. 31, 2015 | |
Recently Issued Accounting Standards, Not Yet Adopted | (4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED Revenue from Contracts with Customers (ASC 606) In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard. The new requirements will be effective for PHI beginning January 1, 2018, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2018. Early adoption is permitted, but not before January 1, 2017. PHI is currently evaluating the potential impact of this new guidance on its consolidated financial statements and which implementation approach to select. Business Combination (ASC 805) In September 2015, the FASB issued new guidance on adjustments to provisional amounts recognized in a business combination, which are currently recognized on a retrospective basis. Under the new requirements, adjustments will be recognized in the reporting period in which the adjustments are determined. The effects of changes in depreciation, amortization, or other income arising from changes to the provisional amounts, if any, are included in earnings of the reporting period in which the adjustments to the provisional amounts are determined. An entity is also required to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The new requirements will be effective for PHI beginning January 1, 2016, and are required to be implemented on a prospective basis. Early adoption is permitted. PHI currently anticipates it may be affected by the new guidance if its Merger with Exelon is consummated. |
Potomac Electric Power Co [Member] | |
Recently Issued Accounting Standards, Not Yet Adopted | (4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED Revenue from Contracts with Customers (ASC 606) In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard. The new requirements will be effective for Pepco beginning January 1, 2018, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2018. Early adoption is permitted, but not before January 1, 2017. Pepco is currently evaluating the potential impact of this new guidance on its financial statements and which implementation approach to select. Business Combination (ASC 805) In September 2015, the FASB issued new guidance on adjustments to provisional amounts recognized in a business combination, which are currently recognized on a retrospective basis. Under the new requirements, adjustments will be recognized in the reporting period in which the adjustments are determined. The effects of changes in depreciation, amortization, or other income arising from changes to the provisional amounts, if any, are included in earnings of the reporting period in which the adjustments to the provisional amounts are determined. An entity is also required to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The new requirements will be effective for Pepco beginning January 1, 2016, and are required to be implemented on a prospective basis. Early adoption is permitted. Pepco currently anticipates it may be affected by the new guidance if its Merger with Exelon is consummated. |
Delmarva Power & Light Co/De [Member] | |
Recently Issued Accounting Standards, Not Yet Adopted | (4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED Revenue from Contracts with Customers (ASC 606) In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard. The new requirements will be effective for DPL beginning January 1, 2018, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2018. Early adoption is permitted, but not before January 1, 2017. DPL is currently evaluating the potential impact of this new guidance on its financial statements and which implementation approach to select. Business Combination (ASC 805) In September 2015, the FASB issued new guidance on adjustments to provisional amounts recognized in a business combination, which are currently recognized on a retrospective basis. Under the new requirements, adjustments will be recognized in the reporting period in which the adjustments are determined. The effects of changes in depreciation, amortization, or other income arising from changes to the provisional amounts, if any, are included in earnings of the reporting period in which the adjustments to the provisional amounts are determined. An entity is also required to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The new requirements will be effective for DPL beginning January 1, 2016, and are required to be implemented on a prospective basis. Early adoption is permitted. DPL currently anticipates it may be affected by the new guidance if its Merger with Exelon is consummated. |
Atlantic City Electric Co [Member] | |
Recently Issued Accounting Standards, Not Yet Adopted | (4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED Revenue from Contracts with Customers (ASC 606) In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard. The new requirements will be effective for ACE beginning January 1, 2018, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2018. Early adoption is permitted, but not before January 1, 2017. ACE is currently evaluating the potential impact of this new guidance on its consolidated financial statements and which implementation approach to select. Business Combination (ASC 805) In September 2015, the FASB issued new guidance on adjustments to provisional amounts recognized in a business combination, which are currently recognized on a retrospective basis. Under the new requirements, adjustments will be recognized in the reporting period in which the adjustments are determined. The effects of changes in depreciation, amortization, or other income arising from changes to the provisional amounts, if any, are included in earnings of the reporting period in which the adjustments to the provisional amounts are determined. An entity is also required to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The new requirements will be effective for ACE beginning January 1, 2016, and are required to be implemented on a prospective basis. Early adoption is permitted. ACE currently anticipates it may be affected by the new guidance if its Merger with Exelon is consummated. |
Segment Information
Segment Information | 12 Months Ended |
Dec. 31, 2015 | |
Segment Information | (5) SEGMENT INFORMATION Pepco Holdings’ management has identified its operating segments at December 31, 2015 as Power Delivery and Pepco Energy Services. In the tables below, the Corporate and Other column is included to reconcile the segment data with consolidated data and includes unallocated Pepco Holdings’ (parent company) capital costs, such as financing costs. During 2013, PHI completed the termination of its interests in its cross-border energy lease investments that had been maintained by PHI through its wholly- owned subsidiary, PCI. As a result, the cross-border energy lease investments, which comprised substantially all of the operations of the former Other Non-Regulated segment, have been accounted for as discontinued operations. The remaining operations of the former Other Non-Regulated segment, which no longer meet the definition of a separate segment for financial reporting purposes, have been included in Corporate and Other. Segment financial information for continuing operations at and for the years ended December 31, 2015, 2014 and 2013, is as follows: Year Ended December 31, 2015 Power Delivery Pepco Energy Services Corporate and Other (a) PHI Consolidated (millions of dollars) Operating Revenue $ 4,805 $ 223 $ (5 ) $ 5,023 Operating Expenses (b) 4,124 (c) 224 2 4,350 Operating Income (Loss) 681 (1 ) (7 ) 673 Interest Expense 238 — 42 280 Other Income 36 1 17 (d) 54 Income Tax Expense (Benefit) (e) 177 (4 ) (44 ) 129 Net Income from Continuing Operations 302 4 12 318 Total Assets 14,413 221 1,692 16,326 Construction Expenditures $ 1,196 $ 3 $ 31 $ 1,230 (a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to Power Delivery for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit Power Delivery. These expenditures are recorded as incurred in Corporate and Other and are allocated to Power Delivery once the assets are placed in service. Corporate and Other includes intercompany amounts of $(5) million for Operating Revenue, $(4) million for Operating Expenses and $(5) million for Interest Expense. (b) Includes depreciation and amortization expense of $651 million, consisting of $606 million for Power Delivery, $4 million for Pepco Energy Services and $41 million for Corporate and Other. (c) Includes $46 million ($27 million after-tax) related to gains on sales of land at Pepco. (d) Includes $15 million ($10 million after-tax) increase in fair value of preferred stock derivative. (e) Includes tax benefit of $3 million for Power Delivery, $1 million for Pepco Energy Services and $43 million for Corporate and Other associated with the Global Tax Settlement. Year Ended December 31, 2014 Power Delivery Pepco Energy Services Corporate and Other (a) PHI Consolidated (millions of dollars) Operating Revenue $ 4,607 $ 278 $ (7 ) $ 4,878 Operating Expenses (b) 3,916 354 (c) 4 4,274 Operating Income (Loss) 691 (76 ) (11 ) 604 Interest Expense 226 1 41 268 Other Income 40 2 2 44 Income Tax Expense (Benefit) 185 (36 ) (11 ) 138 Net Income (Loss) from Continuing Operations 320 (39 ) (39 ) 242 Total Assets 13,636 249 1,704 15,589 Construction Expenditures $ 1,144 $ 3 $ 76 $ 1,223 (a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to Power Delivery for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit Power Delivery. These expenditures are recorded as incurred in Corporate and Other and are allocated to Power Delivery once the assets are placed in service. Corporate and Other includes intercompany amounts of $(7) million for Operating Revenue, $(7) million for Operating Expenses and $(4) million for Interest Expense. (b) Includes depreciation and amortization expense of $549 million, consisting of $511 million for Power Delivery, $7 million for Pepco Energy Services and $31 million for Corporate and Other. (c) Includes impairment losses of $81 million ($48 million after-tax) associated with Pepco Energy Services’ combined heat and power thermal generating facilities and operations in Atlantic City. Year Ended December 31, 2013 Power Delivery Pepco Energy Services Corporate and Other (a) PHI Consolidated (millions of dollars) Operating Revenue $ 4,472 $ 203 $ (9 ) $ 4,666 Operating Expenses (b) 3,828 201 (c) (31 ) 3,998 Operating Income 644 2 22 668 Interest Expense 228 1 44 273 Other Income 28 3 3 34 Income Tax Expense (d) 155 1 163 (e) 319 Net Income (Loss) from Continuing Operations 289 3 (182 ) 110 Total Assets 12,868 337 1,573 14,778 Construction Expenditures $ 1,194 $ 4 $ 112 $ 1,310 (a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to Power Delivery for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit Power Delivery. These expenditures are recorded as incurred in Corporate and Other and are allocated to Power Delivery once the assets are placed in service. Corporate and Other includes intercompany amounts of $(10) million for Operating Revenue, $(9) million for Operating Expenses and $(5) million for Interest Expense. (b) Includes depreciation and amortization expense of $473 million, consisting of $439 million for Power Delivery, $6 million for Pepco Energy Services and $28 million for Corporate and Other. (c) Includes impairment losses of $4 million ($3 million after-tax) associated with Pepco Energy Services’ landfill gas-fired electric generation facility. (d) Includes after-tax interest associated with uncertain and effectively settled tax positions allocated to each member of the consolidated group, including a $12 million interest benefit for Power Delivery and interest expense of $66 million for Corporate and Other. (e) Includes non-cash charges of $101 million representing the establishment of valuation allowances against certain deferred tax assets of PCI included in Corporate and Other. |
Potomac Electric Power Co [Member] | |
Segment Information | (5) SEGMENT INFORMATION Pepco operates its business as one regulated utility segment, which includes all of its services as described above. |
Delmarva Power & Light Co/De [Member] | |
Segment Information | (5) SEGMENT INFORMATION DPL operates its business as one regulated utility segment, which includes all of its services as described above. |
Atlantic City Electric Co [Member] | |
Segment Information | (5) SEGMENT INFORMATION ACE operates its business as one regulated utility segment, which includes all of its services as described above. |
Goodwill
Goodwill | 12 Months Ended |
Dec. 31, 2015 | |
Goodwill | (6) GOODWILL Substantially all of PHI’s goodwill balance as of December 31, 2015 and 2014 was generated by Pepco’s acquisition of Conectiv (now Conectiv, LLC, to be referred to herein as Conectiv) in 2002 and is allocated entirely to the Power Delivery reporting unit based on the aggregation of its regulated public utility company components for purposes of assessing impairment under FASB guidance on goodwill and other intangibles (ASC 350). PHI performs an annual impairment assessment as of November 1 each year, or more frequently if indicators of potential impairment exist, to determine whether it is more likely than not that the fair value of a reporting unit to which goodwill relates is less than its carrying value. In evaluating goodwill for impairment, PHI first assesses qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. For reporting units in which PHI concludes that it is more likely than not that the fair value is more than its carrying value, goodwill is not considered impaired and PHI is not required to perform the two-step goodwill impairment test. Qualitative factors considered in this assessment include industry and market considerations, including the price per share of PHI common stock, overall financial performance, lack of significant changes in any key inputs to the prior year impairment test, including the discount rate and forecasted cash flows, and other relevant events and factors affecting the reporting unit. For reporting units in which PHI concludes that it is more likely than not that the fair value is less than its carrying value, PHI performs the first step of the goodwill impairment test, which compares the fair value of the reporting unit to its carrying value. If the fair value of the reporting unit exceeds the carrying value of the net assets assigned to that unit, goodwill is not considered impaired and PHI is not required to perform additional testing. If the carrying value of the net assets assigned to the reporting unit exceeds the fair value of the reporting unit, then PHI must perform the second step of the goodwill impairment test to determine the implied fair value of the reporting unit’s goodwill. If PHI determines during this second step that the carrying value of a reporting unit’s goodwill exceeds its implied fair value, PHI records an impairment loss equal to the difference. For the annual impairment assessment in 2015, PHI qualitatively determined for its Power Delivery reporting unit that it was more likely than not that fair value exceeded carrying value. As a result, PHI did not perform the two-step goodwill impairment test on the Power Delivery reporting unit. As of December 31, 2015 and 2014, PHI’s goodwill balance was $1,406 million and $1,407 million, respectively, which is net of accumulated impairment losses of $12 million and $18 million, respectively. |
Delmarva Power & Light Co/De [Member] | |
Goodwill | (6) GOODWILL All of DPL’s goodwill was generated by its acquisition of Conowingo Power Company in 1995. DPL performs an annual impairment assessment as of November 1 of each year, or more frequently if indicators of potential impairment exist, to determine whether it is more likely than not that the fair value of the DPL reporting unit to which goodwill relates is less than its carrying value. In evaluating goodwill for impairment, DPL first assesses qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If DPL concludes that it is more likely than not that the fair value is more than its carrying value, goodwill is not considered impaired and DPL is not required to perform the two-step goodwill impairment test. Qualitative factors considered in this assessment include industry and market considerations, overall financial performance, changes in any key inputs to the prior year impairment test, including the discount rate, and other relevant events and factors affecting the reporting unit. If DPL concludes that it is more likely than not that the fair value is less than its carrying value, DPL performs the first step of the goodwill impairment test, which compares DPL’s fair value to its carrying value. If DPL’s fair value exceeds the carrying value of DPL’s net assets, goodwill is not considered impaired and DPL is not required to perform additional testing. If the carrying value of DPL’s net assets exceeds DPL’s fair value, then DPL must perform the second step of the goodwill impairment test to determine the implied fair value of DPL’s goodwill. If DPL determines during this second step that the carrying value of DPL’s goodwill exceeds its implied fair value, DPL records an impairment loss equal to the difference. For the annual impairment assessment in 2015, DPL qualitatively determined that it was more likely than not that fair value exceeded carrying value. As a result, DPL did not perform the two-step goodwill impairment test on that reporting unit. As of December 31, 2015 and 2014, DPL’s goodwill balance was $8 million. There are no accumulated impairment losses. |
Regulatory Matters
Regulatory Matters | 12 Months Ended |
Dec. 31, 2015 | |
Regulatory Matters | (7) REGULATORY MATTERS Regulatory Assets and Regulatory Liabilities The components of Pepco Holdings’ regulatory asset and liability balances at December 31, 2015 and 2014 are as follows: 2015 2014 (millions of dollars) Regulatory Assets Pension and other postretirement benefit costs $ 910 $ 946 Demand-side management costs 403 329 Smart Grid costs 266 261 Recoverable income taxes 224 274 Securitized stranded costs 202 278 Incremental storm restoration costs 43 51 Deferred debt extinguishment costs 36 42 Deferred energy supply costs 32 73 Recoverable workers’ compensation and long-term disability costs 31 30 MAPP abandonment costs 7 33 Deferred losses on gas derivatives 2 4 Other 90 88 Total Regulatory Assets $ 2,246 $ 2,409 Regulatory Liabilities Asset removal costs $ 211 $ 250 Reserves for FERC ROE transmission challenges 32 4 Federal and state tax benefits, related to securitized stranded costs 13 8 Deferred income taxes due to customers 12 44 Deferred energy supply costs 11 3 Other 29 34 Total Regulatory Liabilities $ 308 $ 343 A description for each category of regulatory assets and regulatory liabilities follows: Pension and OPEB Costs: Demand-Side Management Costs: Smart Grid Costs: Recoverable Income Taxes: Securitized Stranded Costs: Incremental Storm Restoration Costs: Deferred Debt Extinguishment Costs: Deferred Energy Supply Costs: Recoverable Workers’ Compensation and Long-Term Disability Costs MAPP Abandonment Costs: Deferred Losses on Gas Derivatives Other: Asset Removal Costs: Reserves for FERC ROE Transmission Challenges Federal and State Tax Benefits, Related to Securitized Stranded Costs: Deferred Income Taxes Due to Customers: Other: Rate Proceedings As further described in Note (1), “Organization,” on April 29, 2014, PHI entered into the Merger Agreement with Exelon and Merger Sub. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, PHI and its subsidiaries may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than pursuing the conclusion of certain proceedings, as described below. To date, PHI has not requested such consent from Exelon and has not filed any new distribution base rate cases since entering into the Merger Agreement. Bill Stabilization Adjustment Each of PHI’s utility subsidiaries proposed in each of its respective jurisdictions the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. A decoupling mechanism, the BSA, was approved and implemented for Pepco and DPL electric service in Maryland and for Pepco electric service in the District of Columbia. None of the other jurisdictions have to date adopted decoupling proposals. Delaware Electric Distribution Base Rates In March 2013, DPL submitted an application with the DPSC to increase its electric distribution base rates. The application sought approval of an annual rate increase of approximately $42 million (adjusted by DPL to approximately $39 million on September 20, 2013), based on a requested ROE of 10.25%. The requested rate increase sought to recover expenses associated with DPL’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. In August 2014, the DPSC issued a final order in this proceeding providing for an annual increase in DPL’s electric distribution base rates of approximately $15.1 million, based on an ROE of 9.70%. The new rates became effective on May 1, 2014. In September 2014, DPL filed an appeal with the Delaware Superior Court of the DPSC’s August 2014 order in this proceeding, seeking the court’s review of the DPSC’s decision relating to the recovery of costs associated with one component of employee compensation, certain retirement benefits and credit facility expenses. The Division of the Public Advocate filed a cross-appeal in September 2014, pertaining to the treatment of a prepaid pension expense and other postretirement benefit obligations in base rates. Under the settlement agreement related to the Merger described below in “Merger Approval Proceedings – Delaware,” the parties agreed to suspend the appeal and, if the Merger is completed, to the withdrawal of the appeal and the cross-appeal with prejudice. Forward Looking Rate Plan In October 2013, DPL filed a multi-year rate plan, referred to as the Forward Looking Rate Plan (FLRP). As proposed, the FLRP would provide for annual electric distribution base rate increases over a four-year period in the aggregate amount of approximately $56 million. The FLRP as proposed provides the opportunity to achieve estimated earned ROEs of 7.41% and 8.80% in years one and two, respectively, and 9.75% in both years three and four of the plan. In addition, DPL proposed that as part of the FLRP, in order to provide a higher minimum required standard of reliability for DPL’s customers than that to which DPL is currently subject, the standards by which DPL’s reliability is measured would be made more stringent in each year of the FLRP. DPL has also offered to refund an aggregate of $500,000 to customers in each year of the FLRP that it fails to meet the proposed stricter minimum reliability standards. In October 2013, the DPSC opened a docket for the purpose of reviewing the details of the FLRP, but stated that it would not address the FLRP until the electric distribution base rate case discussed above was concluded. Although the rate case has been concluded, a schedule for the FLRP docket has not yet been established. Under the Merger Agreement, DPL is permitted to pursue this matter; however, under the settlement agreement related to the Merger described below in “Merger Approval Proceedings – Delaware,” DPL agreed to withdraw the FLRP if the Merger is completed, without prejudice to the right to make future filings with the DPSC proposing alternative regulatory methodologies that could include, but are not limited to, a multi-year rate plan. Gas Cost Rates DPL makes an annual GCR filing with the DPSC for the purpose of allowing DPL to recover natural gas procurement costs through customer rates. In August 2015, DPL made its 2015 GCR filing. The rates proposed in the 2015 GCR filing would result in a GCR decrease of approximately 26%, primarily reflecting lower natural gas prices. On September 22, 2015, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2015, subject to refund and pending final DPSC approval. Under the Merger Agreement, DPL is permitted to continue to file its required annual GCR cases in Delaware. Maryland Pepco Electric Distribution Base Rates 2011 Base Rate Proceeding In December 2011, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $68.4 million (subsequently adjusted by Pepco to approximately $66.2 million), based on a requested ROE of 10.75%. In July 2012, the MPSC issued an order approving an annual rate increase of approximately $18.1 million, based on an ROE of 9.31%. Among other things, the order also authorized Pepco to recover the actual cost of AMI meters installed during the 2011 test year, stating that cost recovery for AMI deployment will be allowed in future rate cases in which Pepco demonstrates that the system is cost effective. The new rates became effective on July 20, 2012. The Maryland Office of People’s Counsel has sought rehearing on the portion of the order allowing Pepco to recover the costs of AMI meters installed during the test year; that motion remains pending. 2012 Base Rate Proceeding – Phase I In November 2012, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $60.8 million, based on a requested ROE of 10.25%. In July 2013, the MPSC issued an order in this proceeding approving an annual rate increase of approximately $27.9 million, based on an ROE of 9.36%. The order excludes the cost of AMI meters from Pepco’s rate base until such time as Pepco demonstrates the cost effectiveness of the AMI system; as a result, costs for AMI meters incurred with respect to the 2012 test year and beyond will be treated as other incremental AMI costs incurred in conjunction with the deployment of the AMI system that are deferred and on which a carrying charge is deferred, but only until such cost effectiveness has been demonstrated and such costs are included in rates. However, MPSC’s July 2012 order issued in connection with Pepco’s 2011 base rate proceeding, which allowed Pepco to recover the costs of meters installed during the 2011 test year for that case, remains in effect. The July 2013 order also approved a Grid Resiliency Charge, which went into effect on January 1, 2014, for recovery of costs totaling approximately $24.0 million associated with Pepco’s proposed plan to accelerate investments related to certain priority feeders, provided that, before implementing the surcharge, Pepco (i) provides additional information to the MPSC related to performance objectives, milestones and costs, and (ii) makes annual filings with the MPSC thereafter concerning this project, which will permit the MPSC to establish the applicable Grid Resiliency Charge rider for each following year. These conditions have been met. The MPSC rejected certain other cost recovery mechanisms, including Pepco’s proposed reliability performance-based mechanism. The new rates were effective on July 12, 2013. In July 2013, Pepco filed a notice of appeal of the July 2013 order in the Circuit Court for Baltimore City. Other parties also filed notices of appeal, which were consolidated with Pepco’s appeal. In its appeal, Pepco asserted that the MPSC erred in failing to grant Pepco an adequate ROE, denying a number of other cost recovery mechanisms and limiting Pepco’s test year data to no more than four months of forecasted data in future rate cases. The other parties primarily asserted that the MPSC erred or acted arbitrarily and capriciously in allowing the recovery of certain costs by Pepco, in approving the Grid Resiliency Charge, and in refusing to reduce Pepco’s rate base by known and measurable accumulated depreciation. In November 2014, the Circuit Court issued an order reversing the MPSC’s decision on Pepco’s ROE and directing the MPSC to make more specific findings regarding the impact of improved service reliability and the BSA in calculating Pepco’s ROE. On all other issues that were the subject of an appeal, the Circuit Court affirmed the MPSC’s July 2013 order. Other parties to this proceeding filed notices of appeal of the Circuit Court’s decision to the Maryland Court of Special Appeals. On December 15, 2015, the Court of Special Appeals issued its decision in this matter (i) affirming the Circuit Court’s decision upholding the MPSC’s decision to approve the use of the Grid Resiliency Charge for Pepco, and (ii) reversing the Circuit Court on the ROE issue, finding that the MPSC’s original ROE of 9.36% was within the zone of reasonableness. Because none of the parties to the proceeding, including Pepco, appealed this Court of Special Appeals decision, the MPSC decision is now final. 2013 Base Rate Proceeding – Phase I In December 2013, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $43.3 million (adjusted by Pepco to approximately $37.4 million on April 15, 2014), based on a requested ROE of 10.25%. The requested rate increase sought to recover expenses associated with Pepco’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. In July 2014, the MPSC issued an order approving an annual rate increase of approximately $8.75 million, based on an ROE of 9.62%. The new rates became effective on July 4, 2014. In July 2014, Pepco filed a petition for rehearing seeking reconsideration of the recovery of certain expenses, which the MPSC denied by its order issued in November 2014 (described below). In December 2014, Pepco filed a petition for judicial review of this MPSC order with the Circuit Court for Baltimore City. On August 7, 2015, the Circuit Court for Baltimore City affirmed the MPSC’s decision and denied Pepco’s appeal. Pepco has elected not to appeal the decision of the Circuit Court. 2012 and 2013 Base Rate Proceedings – Phase II In August 2014, the MPSC issued an order establishing a Phase II proceeding in the 2012 base rate case described above (the 2012 Phase II proceeding) to address the tax implications of Pepco’s net operating loss carryforward (NOLC), which had impacted certain of Pepco’s rate adjustments in the 2012 base rate proceeding. Pepco filed a motion to dismiss the 2012 Phase II proceeding, asserting that the MPSC no longer has jurisdiction over the 2012 base rate case due to appeals having been filed by numerous parties. In September 2014, the MPSC issued an order staying the 2012 Phase II proceeding until further notice. In a similar Phase II proceeding in the 2013 base rate case described above, the MPSC issued an order in November 2014 upholding Pepco’s treatment of the NOLC. Although Pepco believes the November 2014 MPSC order should be dispositive of the issues raised in the 2012 Phase II proceeding, the 2012 Phase II proceeding has remained open pending the resolution of all appeals of the 2012 base rate proceeding. Now that the MPSC decision in that proceeding is final, the MPSC will have authority to act on Phase II. New Jersey Update and Reconciliation of Certain Under-Recovered Balances In March 2015, ACE submitted its 2015 annual petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the NUGs, and (ii) costs related to surcharges for the New Jersey Societal Benefit Program (a statewide public interest program that is intended to benefit low income customers and address other public policy goals) and for ACE’s uncollected accounts. As filed, the net impact of the proposed changes would have been an annual rate increase of approximately $52.0 million (revised to an increase of approximately $33.9 million on April 17, 2015, based upon updates for actual data through March 31, 2015). On May 19, 2015, the NJBPU approved a stipulation of settlement entered into by the parties providing for a provisional overall annual rate increase of $33.9 million effective June 1, 2015. On September 11, 2015, the NJBPU approved a stipulation of settlement in this proceeding, which made final the provisional rates that were placed into effect as of June 1, 2015, with an adjustment that decreased the rate applicable to the residential class by $1.3 million. This rate increase of approximately $32.6 million will have no effect on ACE’s operating income, since these revenues provide for recovery of deferred costs under an approved deferral mechanism. On February 1, 2016, ACE submitted its 2016 annual petition with the NJBPU seeking to reconcile and update the same categories of charges and costs described in (i) and (ii) in the above paragraph. The net impact of adjusting the charges as proposed is an overall annual rate increase of approximately $8.8 million, including New Jersey Sales and Use Tax. The matter is pending at the NJBPU and will be updated for January through March 2016 actual data. ACE has requested that the NJBPU place the new rates into effect by June 1, 2016. Service Extension Contributions Refund Order In July 2013, in compliance with a 2012 Superior Court of New Jersey Appellate Division (Appellate Division) court decision, the NJBPU released an order requiring utilities to issue refunds to persons or entities that paid non-refundable contributions for utility service extensions to certain areas described as “Areas Not Designated for Growth.” The order is limited to eligible contributions paid between March 20, 2005 and December 20, 2009. ACE is processing the refund requests that meet the eligibility criteria established in the order as they are received. Although ACE estimates that it received approximately $11 million of contributions between March 20, 2005 and December 20, 2009, it is currently unable to reasonably estimate the amount that it may be required to refund using the eligibility criteria established by the order. Since the July 2013 order was released, ACE has paid less than $1 million in refund claims, the validity of each of which is investigated by ACE prior to making any such refunds. In September 2014, the NJBPU commenced a rulemaking proceeding to further implement the directives of the Appellate Division decision. In November 2015, the NJBPU adopted new regulations that remove provisions distinguishing between growth areas and not-for-growth areas and provide formulae for allocating extension costs. At this time, ACE does not expect the amount it is ultimately required to refund will have a material effect on its consolidated financial condition, results of operations or cash flows, as the amount refunded will generally increase the value of ACE’s property, plant and equipment and may ultimately be recovered through depreciation expense and cost of service in future electric distribution base rate cases. Generic Consolidated Tax Adjustment Proceeding In January 2013, the NJBPU initiated a generic proceeding to examine whether a consolidated tax adjustment (CTA) should continue to be used, and if so, how it should be calculated in determining a utility’s cost of service. Under the NJBPU’s current policy, when a New Jersey utility is included in a consolidated group income tax return, an allocated amount of any reduction in the consolidated group’s taxes as a result of losses by affiliates is used to reduce the utility’s rate base, upon which the utility earns a return. This policy has negatively impacted ACE’s electric distribution base rate case outcomes and ACE’s position is that the CTA should be eliminated. In an order issued in October 2014, the NJBPU determined that it is appropriate for affected consolidated groups to continue to include a CTA in New Jersey base rate filings, but that the CTA calculation will be modified to limit the look-back period for the calculation to five years, exclude transmission assets from the calculation, and allocate 25 percent of the final CTA amount as a reduction to the distribution revenue requirement. ACE anticipates that this revised methodology will significantly reduce the negative effects of the CTA in future base rate cases. In November 2014, the New Jersey Division of Rate Counsel filed an appeal of the NJBPU’s CTA order in the Appellate Division. No stay of the October 2014 CTA order was requested in connection with the appeal. As such, barring an adverse finding by the Appellate Division, the order is in effect. The appeal remains pending. FERC Transmission ROE Challenges In February 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as the Delaware Municipal Electric Corporation, Inc., filed a joint complaint at FERC against Pepco, DPL and ACE, as well as Baltimore Gas and Electric Company (BGE). The complainants challenged the base ROE and certain protocols regarding the formula rate process associated with the transmission service that the utilities provide. The complainants support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for PHI’s utilities is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. The 10.8% base ROE for facilities placed into service prior to 2006 receives a 50-basis-point incentive adder for being a member of a regional transmission organization. In August 2014, FERC issued an order setting the matters in this proceeding for hearing, but holding the hearing in abeyance pending settlement discussions. The order also (i) directed that the evidence and analysis presented concerning ROE be guided by the new ROE methodology adopted by FERC in another proceeding (discussed below), and (ii) set a 15-month refund period that commenced on February 27, 2013, should a refund result from this proceeding. After settlement discussions among the parties in this matter reached an impasse, the settlement judge, in November 2014, issued an order terminating the settlement discussions and referring the matter to a presiding administrative law judge. In June 2014, FERC issued an order in a proceeding in which the PHI utilities were not involved, in which it adopted a new ROE methodology for electric utilities. This new methodology replaces the existing one-step discounted cash flow analysis (which incorporates only short-term growth rates) traditionally used to derive ROE for electric utilities with the two-step discounted cash flow analysis (which incorporates both short-term and long-term measures of growth) used for natural gas and oil pipelines. As a result of the August 2014 FERC order discussed in the preceding paragraph, Pepco, DPL and ACE applied an estimated ROE based on the two-step methodology announced by FERC for the 15-month period over which each of their transmission revenues would be subject to refund as a result of the challenge, and recorded estimated reserves for the entire 15-month refund period in the second quarter of 2014. On December 8, 2014, the parties that filed the February 2013 complaint filed a second complaint against Pepco, DPL, ACE, as well as BGE, regarding the base transmission ROE, seeking a reduction from 10.8% to 8.8%. By order issued on February 9, 2015, FERC established a hearing on the second complaint and established a second 15-month refund period that commenced on December 8, 2014. Consistent with the prior challenge, Pepco, DPL and ACE applied an estimated ROE based on the two-step methodology described above, and in the fourth quarter of 2014 and in the first, second and third quarters of 2015 established reserves for the estimated refund based on the effective date of the second refund period of December 8, 2014. On February 20, 2015, the chief judge issued an order consolidating the two complaint proceedings and established an initial decision issuance deadline of February 29, 2016. On March 2, 2015, the presiding administrative law judge issued an order establishing a procedural schedule for the consolidated proceedings that provided for the hearing to commence on October 20, 2015. Also during the third quarter of 2015, PHI further evaluated the reserves established for each of the two refund periods and, based on an updated assessment of market conditions, developments in other cases before FERC, litigation risk and other factors, increased its reserves to reflect management’s best estimate of the refund that is expected to result from these consolidated proceedings. A settlement entered into by the parties regarding the protocols (but not the ROE) raised in the February 2013 complaint was submitted to FERC on July 31, 2015 and was approved by FERC in November 2015. On November 6, 2015, the parties filed a settlement agreement with FERC regarding the ROE. This settlement agreement provides for (i) a base ROE of 10.0%, effective March 8, 2016, to which a 50-basis-point incentive adder will be applied for being a member of a regional transmission organization, and (ii) customer refunds in the amount of approximately $9.5 million, $11.9 million, and $14.2 million for ACE, DPL and Pepco, respectively, covering the two 15-month refund periods described above. In addition, under this settlement agreement, no party may file to change the base ROE or any incentives prior to June 1, 2018. The parties have requested that FERC approve this settlement agreement by March 16, 2016, in order to incorporate the new ROE and applicable refunds into each utility’s 2016 transmission formula rate update. As of December 31, 2015, PHI’s reserves for both of the refund periods totaled $32 million as required under the settlement agreement. MPSC New Generation Contract Requirement In April 2012, the MPSC issued an order that requires Maryland electric distribution companies (EDCs) Pepco, DPL and BGE (collectively, the Contract EDCs) to negotiate and enter into a contract with the winning bidder of a competitive bidding process to build one new power plant in the range of 650 to 700 megawatts (MWs) beginning in 2015, in amounts proportional to their relative SOS loads. Under the terms of the order, the winning bidder was to construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with an originally expected commercial operation date of June 1, 2015 (which is now deferred pending the outcome of the proceedings discussed below), and each of the Contract EDCs was to recover its costs associated with the contract through surcharges on its respective SOS customers. In response to a complaint filed by a group of generating companies in the PJM region, in September 2013, the U.S. District Court for the District of Maryland (the Federal District Court) issued a ruling that the MPSC’s April 2012 order violated the Supremacy Clause of the U.S. Constitution by attempting to regulate wholesale prices. In contrast, in October 2013, in response to appeals filed by the Contract EDCs and other parties, the Maryland Circuit Court for Baltimore City (the Maryland Circuit Court) upheld the MPSC’s orders requiring the Contract EDCs to enter into the contracts. In October 2013, the Federal District Court issued an order ruling that the contracts are illegal and unenforceable. The Contract EDCs, the Maryland Office of People’s Counsel and one generating company have appealed the Maryland Circuit Court’s decision to the Maryland Court of Special Appeals. In addition, in November 2013 both the winning bidder and the MPSC appealed the Federal District Court decision to the U.S. Court of Appeals for the Fourth Circuit, which affirmed the decision. In November 2014, the winning bidder and the MPSC each petitioned the U.S. Supreme Court to consider hearing an appeal of the Fourth Circuit decision and, on October 19, 2015, the U.S. Supreme Court agreed to review that decision. Assuming the contracts, as currently written, become effective following the satisfaction of all relevant conditions, including the completion of the proceedings discussed above, PHI continues to believe that Pepco and DPL may be required to record their proportional share of the contracts as derivative instruments at fair value and record related regulatory assets of approximately the same amount because Pepco and DPL would be entitled to recover any payments under the contracts from SOS customers. PHI, Pepco and DPL have concluded that any accounting for these contracts would not be required until all legal proceedings related to these contracts and the actions of the MPSC in the related proceeding have been resolved. ACE Standard Offer Capacity Agreements In April 2011, ACE entered into three Standard Offer Capacity Agreements (SOCAs) by order of the NJBPU, each with a different generation company. ACE entered into the SOCAs under protest, as did the other EDCs in New Jersey, arguing that the EDCs were denied due process and that the SOCAs violated certain of the requirements of the New Jersey law under which the SOCAs were established (the NJ SOCA Law). In October 2013, in light of the decision of the U.S. District Court for the District of New Jersey described below, the state appeals of the NJBPU implementation orders filed by the EDCs and generators were dismissed without prejudice, subject to the parties exercising their appellate rights in the Federal courts. In February 2011, ACE joined other plaintiffs in an action filed in the U.S. District Court for the District of New Jersey challenging the NJ SOCA Law on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In October 2013, the Federal district court ruled that the NJ SOCA Law is preempted by the Federal Power Act (FPA) and violates the Supremacy Clause, and is therefore null and void. In October 2013, the Federal district court issued an order ruling that the SOCAs are void, invalid and unenforceable, which order was affirmed by the U.S. Court of Appeals for the Third Circuit in September 2014. In November 2014 and December 2014, respectively, one of the generation companies and the NJBPU petitioned the U.S. Supreme Court to consider hearing an appeal of the Third Circuit decision. Although the U.S. Supreme Court agreed to review the Fourth Circuit decision discussed above under “MPSC New Generation Contract Requirement,” it has not yet agreed to review the Third Circuit decision and the petitions for such review remain pending. ACE terminated one of the three SOCAs effective July 1, 2013 due to the occurrence of an event of default on the part of the generation company counterparty. ACE terminated the remaining two SOCAs effective November 19, 2013, in response to the October 2013 Federal district court decision. In response to the October 2013 Federal district court order, ACE, in the fourth quarter of 2013, derecognized both the derivative assets (liabilities) for the estimated fair value of the SOCAs and the related regulatory liabilities (assets) that it had established with respect to the SOCAs. District of Columbia Power Line Undergrounding Initiative In May 2014, the Council of the District of Columbia enacted the Electric Company Infrastructure Improvement Financing Act of 2014 (the Improvement Financing Act), which provides enabling legislation for the District of Columbia Power Line Undergrounding (DC PLUG) initiative. This $1 billion initiative seeks to selectively place underground some of the District of Columbia’s most outage-prone power lines, which lines and surrounding conduit would be owned and maintained by Pepco. The Improvement Financing Act provides that: (i) Pepco is to fund approximately $500 million of the estimated cost to complete the DC PLUG initiative, recovering those costs through a surcharge on the electric bills of Pepco District of Columbia customers; (ii) $375 million of the DC PLUG initiative cost is to be financed by the District of Columbia’s issuance of securitized bonds, which bonds will be repaid through a surcharge on the electric bills of Pepco District of Columbia customers that Pepco will collect on behalf of and remit to the District of Columbia; and (iii) the remaining costs up to $125 million are to be covered by the existing capital projects program of the District of Columbia Department of Transportation (DDOT). Pepco will not earn a return on or a return of the cost of the assets funded with the proceeds of the securitized bonds or assets that are constructed by DDOT under its capital projects program, but ownership and responsibility for the operation and maintenance of such assets will be transferred to Pepco for a nominal amount. In June 2014, Pepco and DDOT filed a Triennial Plan related to the construction of selected underground feeders in the District of Columbia and recovery of Pepco’s investment through a volumetric surcharge (the Triennial Plan), all in accordance with the Improvement Financing Act. In August 2014, Pepco filed an application for the issuance of a financing order to provide for the issuance of the District’s bonds and a volumetric surcharge for the District of Columbia to recover the costs associated with the bond issuance (the DDOT surcharge). In November 2014, the DCPSC issued an order approving the Triennial Plan, including Pepco’s volumetric surcharge, and issued the financing order, including approval of the DDOT surcharge. Together these orders permit (i) Pepco and DDOT to commence proposed construction under the Triennial Plan; (ii) the District of Columbia to issue the necessary bonds to fund the District of Columbia’s portion of the DC PLUG initiative; and (iii) the establishment of the customer surcharges contemplated by the Improvement Financing Act. In December 2014, a party to the proceeding sought reconsideration from the DCPSC of both decisions. Final decisions denying both requests for reconsideration were issued by the DCPSC on January 22, 2015 and February 2, 2015, respectively. In March 2015, a party to the DCPSC proceedings filed with the District o |
Potomac Electric Power Co [Member] | |
Regulatory Matters | (6) REGULATORY MATTERS Regulatory Assets and Regulatory Liabilities The components of Pepco’s regulatory asset and liability balances at December 31, 2015 and 2014 are as follows: 2015 2014 (millions of dollars) Regulatory Assets Demand-side management costs $ 292 $ 238 Smart Grid costs 181 175 Recoverable income taxes 142 148 Recoverable workers’ compensation and long-term disability costs 31 30 Incremental storm restoration costs 19 29 Deferred debt extinguishment costs 19 22 MAPP abandonment costs 4 19 Deferred energy supply costs 3 3 Other 29 33 Total Regulatory Assets $ 720 $ 697 Regulatory Liabilities Asset removal costs $ 58 $ 84 Reserves for FERC ROE transmission challenges 13 2 Deferred income taxes due to customers 6 4 Deferred energy supply costs 5 3 Other 10 11 Total Regulatory Liabilities $ 92 $ 104 A description for each category of regulatory assets and regulatory liabilities follows: Demand-Side Management Costs Smart Grid Costs: Recoverable Income Taxes: Recoverable Workers’ Compensation and Long-Term Disability Costs Incremental Storm Restoration Costs: Deferred Debt Extinguishment Costs: MAPP Abandonment Costs: Deferred Energy Supply Costs: Other: Asset Removal Costs: Reserves for FERC ROE Transmission Challenges Deferred Income Taxes Due to Customers: Other: Rate Proceedings As further described in Note (1), “Organization,” on April 29, 2014, PHI entered into the Merger Agreement with Exelon and Merger Sub. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, PHI and its subsidiaries may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than pursuing the conclusion of certain proceedings, as described below. To date, Pepco has not requested such consent from Exelon and has not filed any new distribution base rate cases since entering into the Merger Agreement. Bill Stabilization Adjustment A decoupling mechanism, the BSA, was approved and implemented for Pepco electric service in Maryland and in the District of Columbia. Maryland Pepco Electric Distribution Base Rates 2011 Base Rate Proceeding In December 2011, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $68.4 million (subsequently adjusted by Pepco to approximately $66.2 million), based on a requested ROE of 10.75%. In July 2012, the MPSC issued an order approving an annual rate increase of approximately $18.1 million, based on an ROE of 9.31%. Among other things, the order also authorized Pepco to recover the actual cost of AMI meters installed during the 2011 test year, stating that cost recovery for AMI deployment will be allowed in future rate cases in which Pepco demonstrates that the system is cost effective. The new rates became effective on July 20, 2012. The Maryland Office of People’s Counsel has sought rehearing on the portion of the order allowing Pepco to recover the costs of AMI meters installed during the test year; that motion remains pending. 2012 Base Rate Proceeding – Phase I In November 2012, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $60.8 million, based on a requested ROE of 10.25%. In July 2013, the MPSC issued an order in this proceeding approving an annual rate increase of approximately $27.9 million, based on an ROE of 9.36%. The order excludes the cost of AMI meters from Pepco’s rate base until such time as Pepco demonstrates the cost effectiveness of the AMI system; as a result, costs for AMI meters incurred with respect to the 2012 test year and beyond will be treated as other incremental AMI costs incurred in conjunction with the deployment of the AMI system that are deferred and on which a carrying charge is deferred, but only until such cost effectiveness has been demonstrated and such costs are included in rates. However, MPSC’s July 2012 order issued in connection with Pepco’s 2011 base rate proceeding, which allowed Pepco to recover the costs of meters installed during the 2011 test year for that case, remains in effect. The July 2013 order also approved a Grid Resiliency Charge, which went into effect on January 1, 2014, for recovery of costs totaling approximately $24.0 million associated with Pepco’s proposed plan to accelerate investments related to certain priority feeders, provided that, before implementing the surcharge, Pepco (i) provides additional information to the MPSC related to performance objectives, milestones and costs, and (ii) makes annual filings with the MPSC thereafter concerning this project, which will permit the MPSC to establish the applicable Grid Resiliency Charge rider for each following year. These conditions have been met. The MPSC rejected certain other cost recovery mechanisms, including Pepco’s proposed reliability performance-based mechanism. The new rates were effective on July 12, 2013. In July 2013, Pepco filed a notice of appeal of the July 2013 order in the Circuit Court for Baltimore City. Other parties also filed notices of appeal, which were consolidated with Pepco’s appeal. In its appeal, Pepco asserted that the MPSC erred in failing to grant Pepco an adequate ROE, denying a number of other cost recovery mechanisms and limiting Pepco’s test year data to no more than four months of forecasted data in future rate cases. The other parties primarily asserted that the MPSC erred or acted arbitrarily and capriciously in allowing the recovery of certain costs by Pepco, in approving the Grid Resiliency Charge, and in refusing to reduce Pepco’s rate base by known and measurable accumulated depreciation. In November 2014, the Circuit Court issued an order reversing the MPSC’s decision on Pepco’s ROE and directing the MPSC to make more specific findings regarding the impact of improved service reliability and the BSA in calculating Pepco’s ROE. On all other issues that were the subject of an appeal, the Circuit Court affirmed the MPSC’s July 2013 order. Other parties to this proceeding filed notices of appeal of the Circuit Court’s decision to the Maryland Court of Special Appeals. On December 15, 2015, the Court of Special Appeals issued its decision in this matter (i) affirming the Circuit Court’s decision upholding the MPSC’s decision to approve the use of the Grid Resiliency Charge for Pepco, and (ii) reversing the Circuit Court on the ROE issue, finding that the MPSC’s original ROE of 9.36% was within the zone of reasonableness. Because none of the parties to the proceeding, including Pepco, appealed this Court of Special Appeals decision, the MPSC decision is now final. 2013 Base Rate Proceeding – Phase I In December 2013, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $43.3 million (adjusted by Pepco to approximately $37.4 million on April 15, 2014), based on a requested ROE of 10.25%. The requested rate increase sought to recover expenses associated with Pepco’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. In July 2014, the MPSC issued an order approving an annual rate increase of approximately $8.75 million, based on an ROE of 9.62%. The new rates became effective on July 4, 2014. In July 2014, Pepco filed a petition for rehearing seeking reconsideration of the recovery of certain expenses, which the MPSC denied by its order issued in November 2014 (described below). In December 2014, Pepco filed a petition for judicial review of this MPSC order with the Circuit Court for Baltimore City. On August 7, 2015, the Circuit Court for Baltimore City affirmed the MPSC’s decision and denied Pepco’s appeal. Pepco has elected not to appeal the decision of the Circuit Court. 2012 and 2013 Base Rate Proceedings – Phase II In August 2014, the MPSC issued an order establishing a Phase II proceeding in the 2012 base rate case described above (the 2012 Phase II proceeding) to address the tax implications of Pepco’s net operating loss carryforward (NOLC), which had impacted certain of Pepco’s rate adjustments in the 2012 base rate proceeding. Pepco filed a motion to dismiss the 2012 Phase II proceeding, asserting that the MPSC no longer has jurisdiction over the 2012 base rate case due to appeals having been filed by numerous parties. In September 2014, the MPSC issued an order staying the 2012 Phase II proceeding until further notice. In a similar Phase II proceeding in the 2013 base rate case described above, the MPSC issued an order in November 2014 upholding Pepco’s treatment of the NOLC. Although Pepco believes the November 2014 MPSC order should be dispositive of the issues raised in the 2012 Phase II proceeding, the 2012 Phase II proceeding has remained open pending the resolution of all appeals of the 2012 base rate proceeding. Now that the MPSC decision in that proceeding is final, the MPSC will have authority to act on Phase II. FERC Transmission ROE Challenges In February 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as the Delaware Municipal Electric Corporation, Inc., filed a joint complaint at FERC against Pepco and its affiliates, Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (ACE), as well as Baltimore Gas and Electric Company (BGE). The complainants challenged the base ROE and certain protocols regarding the formula rate process associated with the transmission service that the utilities provide. The complainants support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for PHI’s utilities is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. The 10.8% base ROE for facilities placed into service prior to 2006 receives a 50-basis-point incentive adder for being a member of a regional transmission organization. In August 2014, FERC issued an order setting the matters in this proceeding for hearing, but holding the hearing in abeyance pending settlement discussions. The order also (i) directed that the evidence and analysis presented concerning ROE be guided by the new ROE methodology adopted by FERC in another proceeding (discussed below), and (ii) set a 15-month refund period that commenced on February 27, 2013, should a refund result from this proceeding. After settlement discussions among the parties in this matter reached an impasse, the settlement judge, in November 2014, issued an order terminating the settlement discussions and referring the matter to a presiding administrative law judge. In June 2014, FERC issued an order in a proceeding in which Pepco was not involved, in which it adopted a new ROE methodology for electric utilities. This new methodology replaces the existing one-step discounted cash flow analysis (which incorporates only short-term growth rates) traditionally used to derive ROE for electric utilities with the two-step discounted cash flow analysis (which incorporates both short-term and long-term measures of growth) used for natural gas and oil pipelines. As a result of the August 2014 FERC order discussed in the preceding paragraph, Pepco applied an estimated ROE based on the two-step methodology announced by FERC for the 15-month period over which its transmission revenues would be subject to refund as a result of the challenge, and recorded estimated reserves for the entire 15-month refund period in the second quarter of 2014. On December 8, 2014, the parties that filed the February 2013 complaint filed a second complaint against Pepco, DPL, ACE, as well as BGE, regarding the base transmission ROE, seeking a reduction from 10.8% to 8.8%. By order issued on February 9, 2015, FERC established a hearing on the second complaint and established a second 15-month refund period that commenced on December 8, 2014. Consistent with the prior challenge, Pepco applied an estimated ROE based on the two-step methodology described above, and in the fourth quarter of 2014 and in the first, second and third quarters of 2015 established reserves for the estimated refund based on the effective date of the second refund period of December 8, 2014. On February 20, 2015, the chief judge issued an order consolidating the two complaint proceedings and established an initial decision issuance deadline of February 29, 2016. On March 2, 2015, the presiding administrative law judge issued an order establishing a procedural schedule for the consolidated proceedings that provided for the hearing to commence on October 20, 2015. Also during the third quarter of 2015, Pepco further evaluated the reserves established for each of the two refund periods and, based on an updated assessment of market conditions, developments in other cases before FERC, litigation risk and other factors, increased its reserves to reflect management’s best estimate of the refund that is expected to result from these consolidated proceedings. A settlement entered into by the parties regarding the protocols (but not the ROE) raised in the February 2013 complaint was submitted to FERC on July 31, 2015 and was approved by FERC in November 2015. On November 6, 2015, the parties filed a settlement agreement with FERC regarding the ROE. This settlement agreement provides for (i) a base ROE of 10.0%, effective March 8, 2016, to which a 50-basis-point incentive adder will be applied for being a member of a regional transmission organization, and (ii) customer refunds in the amount of approximately $14.2 million for Pepco covering the two 15-month refund periods described above. In addition, under this settlement agreement, no party may file to change the base ROE or any incentives prior to June 1, 2018. The parties have requested that FERC approve this settlement agreement by March 16, 2016, in order to incorporate the new ROE and applicable refunds into each utility’s 2016 transmission formula rate update. As of December 31, 2015, Pepco’s reserves for both of the refund periods totaled $13 million as required under the settlement agreement. MPSC New Generation Contract Requirement In April 2012, the MPSC issued an order that requires Maryland electric distribution companies (EDCs) Pepco, DPL and BGE (collectively, the Contract EDCs) to negotiate and enter into a contract with the winning bidder of a competitive bidding process to build one new power plant in the range of 650 to 700 megawatts (MWs) beginning in 2015, in amounts proportional to their relative standard offer service (SOS) loads. Under the terms of the order, the winning bidder was to construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with an originally expected commercial operation date of June 1, 2015 (which is now deferred pending the outcome of the proceedings discussed below), and each of the Contract EDCs was to recover its costs associated with the contract through surcharges on its respective SOS customers. In response to a complaint filed by a group of generating companies in the PJM region, in September 2013, the U.S. District Court for the District of Maryland (the Federal District Court) issued a ruling that the MPSC’s April 2012 order violated the Supremacy Clause of the U.S. Constitution by attempting to regulate wholesale prices. In contrast, in October 2013, in response to appeals filed by the Contract EDCs and other parties, the Maryland Circuit Court for Baltimore City (the Maryland Circuit Court) upheld the MPSC’s orders requiring the Contract EDCs to enter into the contracts. In October 2013, the Federal District Court issued an order ruling that the contracts are illegal and unenforceable. The Contract EDCs, the Maryland Office of People’s Counsel and one generating company have appealed the Maryland Circuit Court’s decision to the Maryland Court of Special Appeals. In addition, in November 2013 both the winning bidder and the MPSC appealed the Federal District Court decision to the U.S. Court of Appeals for the Fourth Circuit, which affirmed the decision. In November 2014, the winning bidder and the MPSC each petitioned the U.S. Supreme Court to consider hearing an appeal of the Fourth Circuit decision and, on October 19, 2015, the U.S. Supreme Court agreed to review that decision. Assuming the contracts, as currently written, become effective following the satisfaction of all relevant conditions, including the completion of the proceedings discussed above, Pepco continues to believe that it may be required to record its proportional share of the contracts as derivative instruments at fair value and record related regulatory assets of approximately the same amount because it would be entitled to recover any payments under the contracts from SOS customers. Pepco has concluded that any accounting for these contracts would not be required until all legal proceedings related to these contracts and the actions of the MPSC in the related proceeding have been resolved. District of Columbia Power Line Undergrounding Initiative In May 2014, the Council of the District of Columbia enacted the Electric Company Infrastructure Improvement Financing Act of 2014 (the Improvement Financing Act), which provides enabling legislation for the District of Columbia Power Line Undergrounding (DC PLUG) initiative. This $1 billion initiative seeks to selectively place underground some of the District of Columbia’s most outage-prone power lines, which lines and surrounding conduit would be owned and maintained by Pepco. The Improvement Financing Act provides that: (i) Pepco is to fund approximately $500 million of the estimated cost to complete the DC PLUG initiative, recovering those costs through a surcharge on the electric bills of Pepco District of Columbia customers; (ii) $375 million of the DC PLUG initiative cost is to be financed by the District of Columbia’s issuance of securitized bonds, which bonds will be repaid through a surcharge on the electric bills of Pepco District of Columbia customers that Pepco will collect on behalf of and remit to the District of Columbia; and (iii) the remaining costs up to $125 million are to be covered by the existing capital projects program of the District of Columbia Department of Transportation (DDOT). Pepco will not earn a return on or a return of the cost of the assets funded with the proceeds of the securitized bonds or assets that are constructed by DDOT under its capital projects program, but ownership and responsibility for the operation and maintenance of such assets will be transferred to Pepco for a nominal amount. In June 2014, Pepco and DDOT filed a Triennial Plan related to the construction of selected underground feeders in the District of Columbia and recovery of Pepco’s investment through a volumetric surcharge (the Triennial Plan), all in accordance with the Improvement Financing Act. In August 2014, Pepco filed an application for the issuance of a financing order to provide for the issuance of the District’s bonds and a volumetric surcharge for the District of Columbia to recover the costs associated with the bond issuance (the DDOT surcharge). In November 2014, the DCPSC issued an order approving the Triennial Plan, including Pepco’s volumetric surcharge, and issued the financing order, including approval of the DDOT surcharge. Together these orders permit (i) Pepco and DDOT to commence proposed construction under the Triennial Plan; (ii) the District of Columbia to issue the necessary bonds to fund the District of Columbia’s portion of the DC PLUG initiative; and (iii) the establishment of the customer surcharges contemplated by the Improvement Financing Act. In December 2014, a party to the proceeding sought reconsideration from the DCPSC of both decisions. Final decisions denying both requests for reconsideration were issued by the DCPSC on January 22, 2015 and February 2, 2015, respectively. In March 2015, a party to the DCPSC proceedings filed with the District of Columbia Court of Appeals a petition for review of the order approving the Triennial Plan and the issuance of the financing order. On January 14, 2016, the District of Columbia Court of Appeals affirmed the orders of the DCPSC. On January 27, 2016, the original petitioning party sought rehearing of the District of Columbia Court of Appeals decision. A determination whether the Court of Appeals will rehear the case is pending. Separately, in June 2015, an agency of the federal government served by Pepco asserted that the DDOT surcharge constitutes a tax on end users from which the federal government is immune. PHI is currently evaluating the assertion and the resolution of this matter will likely delay implementation of the DC PLUG initiative. Merger Approval Proceedings District of Columbia On June 18, 2014, Exelon, PHI and Pepco, and certain of their respective affiliates, filed an application with the DCPSC seeking approval of the Merger. To approve the Merger, the DCPSC must find that the Merger is in the public interest. In an order issued August 22, 2014, the DCPSC stated that to make the determination of whether the transaction is in the public interest, it will analyze the transaction in the context of seven factors to determine whether the transaction balances the interests of shareholders and investors with ratepayers and the community, whether the benefits to shareholders do or do not come at the expense of the ratepayers, and whether the transaction produces a direct and tangible benefit to ratepayers. The seven factors identified by the DCPSC are the effects of the transaction on: (i) ratepayers, shareholders, the financial health of the utility standing alone and as merged, and the local economy; (ii) utility management and administrative operations; (iii) the public safety and the safety and reliability of services; (iv) risks associated with all of the affiliated non-jurisdictional business operations, including nuclear operations, of the applicants; (v) the DCPSC’s ability to regulate the utility effectively following the Merger; (vi) competition in the local retail and wholesale markets that impacts the District and District ratepayers; and (vii) conservation of natural resources and preservation of environmental quality. District of Columbia law does not impose any time limit on the DCPSC’s review of the Merger. The DCPSC held evidentiary hearings in March and April of 2015 and the record was closed on May 27, 2015. On August 27, 2015, the DCPSC issued a written order denying the application seeking approval of the Merger. On September 28, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, filed an application for reconsideration before the DCPSC. Following the DCPSC’s decision on reconsideration, Exelon and Pepco Holdings have the option of filing further appeals with the DC Court of Appeals. On October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, entered into the DC Settlement Agreement with the District of Columbia Government, the Office of the People’s Counsel and other parties. Also on October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates filed with the DCPSC the Motion to Reopen requesting consideration of the DC Settlement Agreement and approval of the Merger on such terms and conditions set forth in the DC Settlement Agreement, without condition or modification, and to stay further proceedings on the application for reconsideration filed by the parties on September 28, 2015, and suspend the time period for reconsideration pending the DCPSC’s consideration of the DC Settlement Agreement. On October 28, 2015, the DCPSC approved the Motion to Reopen and set a procedural schedule for its review of this matter. Upon completion of the public input and evidentiary hearings, the record was closed as of December 23, 2015. Although District of Columbia law does not impose any time limit on the DCPSC’s review of the Merger, the parties requested a decision by March 4, 2016. Maryland On August 19, 2014, Exelon, PHI, Pepco, DPL and certain of their respective affiliates, filed an application with the MPSC seeking approval of the Merger. Maryland law requires the MPSC to approve a merger subject to its review if it finds that the merger is consistent with the public interest, convenience and necessity, including its benefits to and impact on consumers. Evidentiary hearings were held beginning on January 26, 2015. On March 10, 2015, Exelon, PHI, Pepco, DPL and certain of their respective affiliates, filed with the MPSC a settlement agreement entered into with one of the stakeholder groups participating in the MPSC approval proceeding. On March 16, 2015, Exelon, PHI, Pepco, DPL and certain of their respective affiliates, filed with the MPSC a settlement agreement entered into with Montgomery and Prince George’s Counties in Maryland, and a number of other parties. On May 15, 2015, the MPSC approved the Merger, with conditions, including conditions that modify and supplement those originally proposed. On May 18, 2015, Pepco Holdings and Exelon announced that they had completed their review of the MPSC’s order approving the Merger and have committed to fulfill the modified, more stringent conditions and package of customer benefits imposed by the MPSC. Multiple parties have filed petitions for judicial review of the MPSC order by the Circuit Court of Queen Anne’s County, Maryland, seeking to appeal the MPSC order. In connection with these proceedings, the Maryland Office of People’s Counsel and several other parties to the Merger proceedings filed motions in the Circuit Court for Queen Anne’s County, Maryland, requesting a stay of the MPSC order. On August 7, 2015, the Circuit Court for Queen Anne’s County denied the motions for stay. On January 8, 2016, the Circuit Court affirmed the MPSC’s order in all respects. On January 20 and 22, 2016, respectively, the Maryland Office of People’s Counsel and environmental groups filed notices of appeal of the Circuit Court’s order to the Maryland Court of Special Appeals. Unless a motion to stay is filed and then granted by the court, the MPSC order will remain in effect during the appeals process. Virginia On June 3, 2014, Exelon, PHI, Pepco and DPL, and certain of their respective affiliates, filed an application with the VSCC seeking approval of the Merger. Virginia law provides that, if the VSCC determines, with or without hearing, that adequate service to the public at just and reasonable rates will not be impaired or jeopardized by granting the application for approval, then the VSCC shall approve a merger with such conditions that the VSCC deems to be appropriate in order to satisfy this standard. On October 7, 2014, the VSCC issued an order approving the Merger. Federal Energy Regulatory Commission On May 30, 2014, Exelon, PHI, Pepco, DPL and ACE, and certain of their respective affiliates, submitted to FERC a Joint Application for Authorization of Disposition of Jurisdictional Assets and Merger under Section 203 of the Federal Power Act. Under that section, FERC shall approve a merger if it finds that the proposed transaction will be consistent with the public interest. On November 20, 2014, FERC issued an order approving the Merger. |
Delmarva Power & Light Co/De [Member] | |
Regulatory Matters | (7) REGULATORY MATTERS Regulatory Assets and Regulatory Liabilities The components of DPL’s regulatory asset and liability balances at December 31, 2015 and 2014 are as follows: 2015 2014 (millions of dollars) Regulatory Assets Demand-side management costs $ 111 $ 91 Smart Grid costs 85 86 Recoverable income taxes 38 84 COPCO acquisition adjustment 13 18 Deferred debt extinguishment costs 10 12 Incremental storm restoration costs 6 7 MAPP abandonment costs 3 14 Deferred energy supply costs 2 12 Deferred losses on gas derivatives 2 4 Other 38 28 Total Regulatory Assets $ 308 $ 356 Regulatory Liabilities Asset removal costs $ 153 $ 166 Reserves for FERC ROE transmission challenges 11 1 Deferred energy supply costs 6 — Deferred income taxes due to customers 3 37 Other 16 21 Total Regulatory Liabilities $ 189 $ 225 A description for each category of regulatory assets and regulatory liabilities follows: Demand-Side Management Costs: Smart Grid Costs: Recoverable Income Taxes: COPCO Acquisition Adjustment: Deferred Debt Extinguishment Costs: Incremental Storm Restoration Costs: MAPP Abandonment Costs: Deferred Energy Supply Costs: Deferred Losses on Gas Derivatives Other: Asset Removal Costs: Reserves for FERC ROE Transmission Challenges Deferred Income Taxes Due to Customers: Other: Rate Proceedings As further described in Note (1), “Organization,” on April 29, 2014, PHI entered into the Merger Agreement with Exelon and Merger Sub. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, PHI and its subsidiaries may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than pursuing the conclusion of certain proceedings, as described below. To date, DPL has not requested such consent from Exelon and has not filed any new distribution base rate cases since entering into the Merger Agreement. Bill Stabilization Adjustment A decoupling mechanism, the BSA, was approved and implemented for DPL electric service in Maryland. DPL’s decoupling proposal in Delaware has not to date been adopted. Delaware Electric Distribution Base Rates In March 2013, DPL submitted an application with the DPSC to increase its electric distribution base rates. The application sought approval of an annual rate increase of approximately $42 million (adjusted by DPL to approximately $39 million on September 20, 2013), based on a requested ROE of 10.25%. The requested rate increase sought to recover expenses associated with DPL’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. In August 2014, the DPSC issued a final order in this proceeding providing for an annual increase in DPL’s electric distribution base rates of approximately $15.1 million, based on an ROE of 9.70%. The new rates became effective on May 1, 2014. In September 2014, DPL filed an appeal with the Delaware Superior Court of the DPSC’s August 2014 order in this proceeding, seeking the court’s review of the DPSC’s decision relating to the recovery of costs associated with one component of employee compensation, certain retirement benefits and credit facility expenses. The Division of the Public Advocate filed a cross-appeal in September 2014, pertaining to the treatment of a prepaid pension expense and other postretirement benefit obligations in base rates. Under the settlement agreement related to the Merger described below in “Merger Approval Proceedings – Delaware,” the parties agreed to suspend the appeal and, if the Merger is completed, to the withdrawal of the appeal and the cross-appeal with prejudice. Forward Looking Rate Plan In October 2013, DPL filed a multi-year rate plan, referred to as the Forward Looking Rate Plan (FLRP). As proposed, the FLRP would provide for annual electric distribution base rate increases over a four-year period in the aggregate amount of approximately $56 million. The FLRP as proposed provides the opportunity to achieve estimated earned ROEs of 7.41% and 8.80% in years one and two, respectively, and 9.75% in both years three and four of the plan. In addition, DPL proposed that as part of the FLRP, in order to provide a higher minimum required standard of reliability for DPL’s customers than that to which DPL is currently subject, the standards by which DPL’s reliability is measured would be made more stringent in each year of the FLRP. DPL has also offered to refund an aggregate of $500,000 to customers in each year of the FLRP that it fails to meet the proposed stricter minimum reliability standards. In October 2013, the DPSC opened a docket for the purpose of reviewing the details of the FLRP, but stated that it would not address the FLRP until the electric distribution base rate case discussed above was concluded. Although the rate case has been concluded, a schedule for the FLRP docket has not yet been established. Under the Merger Agreement, DPL is permitted to pursue this matter; however, under the settlement agreement related to the Merger described below in “Merger Approval Proceedings – Delaware,” DPL agreed to withdraw the FLRP if the Merger is completed, without prejudice to the right to make future filings with the DPSC proposing alternative regulatory methodologies that could include, but are not limited to, a multi-year rate plan. Gas Cost Rates DPL makes an annual GCR filing with the DPSC for the purpose of allowing DPL to recover natural gas procurement costs through customer rates. In August 2015, DPL made its 2015 GCR filing. The rates proposed in the 2015 GCR filing would result in a GCR decrease of approximately 26%, primarily reflecting lower natural gas prices. On September 22, 2015, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2015, subject to refund and pending final DPSC approval. Under the Merger Agreement, DPL is permitted to continue to file its required annual GCR cases in Delaware. FERC Transmission ROE Challenges In February 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as the Delaware Municipal Electric Corporation, Inc., filed a joint complaint at FERC against DPL and its affiliates, Pepco and Atlantic City Electric Company (ACE), as well as Baltimore Gas and Electric Company (BGE). The complainants challenged the base ROE and certain protocols regarding the formula rate process associated with the transmission service that the utilities provide. The complainants support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for PHI’s utilities is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. The 10.8% base ROE for facilities placed into service prior to 2006 receives a 50-basis-point incentive adder for being a member of a regional transmission organization. In August 2014, FERC issued an order setting the matters in this proceeding for hearing, but holding the hearing in abeyance pending settlement discussions. The order also (i) directed that the evidence and analysis presented concerning ROE be guided by the new ROE methodology adopted by FERC in another proceeding (discussed below), and (ii) set a 15-month refund period that commenced on February 27, 2013, should a refund result from this proceeding. After settlement discussions among the parties in this matter reached an impasse, the settlement judge, in November 2014, issued an order terminating the settlement discussions and referring the matter to a presiding administrative law judge. In June 2014, FERC issued an order in a proceeding in which DPL was not involved, in which it adopted a new ROE methodology for electric utilities. This new methodology replaces the existing one-step discounted cash flow analysis (which incorporates only short-term growth rates) traditionally used to derive ROE for electric utilities with the two-step discounted cash flow analysis (which incorporates both short-term and long-term measures of growth) used for natural gas and oil pipelines. As a result of the August 2014 FERC order discussed in the preceding paragraph, DPL applied an estimated ROE based on the two-step methodology announced by FERC for the 15-month period over which its transmission revenues would be subject to refund as a result of the challenge, and recorded estimated reserves for the entire 15-month refund period in the second quarter of 2014. On December 8, 2014, the parties that filed the February 2013 complaint filed a second complaint against Pepco, DPL, ACE, as well as BGE, regarding the base transmission ROE, seeking a reduction from 10.8% to 8.8%. By order issued on February 9, 2015, FERC established a hearing on the second complaint and established a second 15-month refund period that commenced on December 8, 2014. Consistent with the prior challenge, DPL applied an estimated ROE based on the two-step methodology described above, and in the fourth quarter of 2014 and in the first, second and third quarters of 2015 established reserves for the estimated refund based on the effective date of the second refund period of December 8, 2014. On February 20, 2015, the chief judge issued an order consolidating the two complaint proceedings and established an initial decision issuance deadline of February 29, 2016. On March 2, 2015, the presiding administrative law judge issued an order establishing a procedural schedule for the consolidated proceedings that provided for the hearing to commence on October 20, 2015. Also during the third quarter of 2015, DPL further evaluated the reserves established for each of the two refund periods and, based on an updated assessment of market conditions, developments in other cases before FERC, litigation risk and other factors, increased its reserves to reflect management’s best estimate of the refund that is expected to result from these consolidated proceedings. A settlement entered into by the parties regarding the protocols (but not the ROE) raised in the February 2013 complaint was submitted to FERC on July 31, 2015 and was approved by FERC in November 2015. On November 6, 2015, the parties filed a settlement agreement with FERC regarding the ROE. This settlement agreement provides for (i) a base ROE of 10.0%, effective March 8, 2016, to which a 50-basis-point incentive adder will be applied for being a member of a regional transmission organization, and (ii) customer refunds in the amount of approximately $11.9 million for DPL covering the two 15-month refund periods described above. In addition, under this settlement agreement, no party may file to change the base ROE or any incentives prior to June 1, 2018. The parties have requested that FERC approve this settlement agreement by March 16, 2016, in order to incorporate the new ROE and applicable refunds into each utility’s 2016 transmission formula rate update. As of December 31, 2015, DPL’s reserves for both of the refund periods totaled $11 million as required under the settlement agreement. MPSC New Generation Contract Requirement In April 2012, the MPSC issued an order that requires Maryland electric distribution companies (EDCs) Pepco, DPL and BGE (collectively, the Contract EDCs) to negotiate and enter into a contract with the winning bidder of a competitive bidding process to build one new power plant in the range of 650 to 700 megawatts (MWs) beginning in 2015, in amounts proportional to their relative standard offer service (SOS) loads. Under the terms of the order, the winning bidder was to construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with an originally expected commercial operation date of June 1, 2015 (which is now deferred pending the outcome of the proceedings discussed below), and each of the Contract EDCs was to recover its costs associated with the contract through surcharges on its respective SOS customers. In response to a complaint filed by a group of generating companies in the PJM region, in September 2013, the U.S. District Court for the District of Maryland (the Federal District Court) issued a ruling that the MPSC’s April 2012 order violated the Supremacy Clause of the U.S. Constitution by attempting to regulate wholesale prices. In contrast, in October 2013, in response to appeals filed by the Contract EDCs and other parties, the Maryland Circuit Court for Baltimore City (the Maryland Circuit Court) upheld the MPSC’s orders requiring the Contract EDCs to enter into the contracts. In October 2013, the Federal District Court issued an order ruling that the contracts are illegal and unenforceable. The Contract EDCs, the Maryland Office of People’s Counsel and one generating company have appealed the Maryland Circuit Court’s decision to the Maryland Court of Special Appeals. In addition, in November 2013 both the winning bidder and the MPSC appealed the Federal District Court decision to the U.S. Court of Appeals for the Fourth Circuit, which affirmed the decision. In November 2014, the winning bidder and the MPSC each petitioned the U.S. Supreme Court to consider hearing an appeal of the Fourth Circuit decision and, on October 19, 2015, the U.S. Supreme Court agreed to review that decision. Assuming the contracts, as currently written, become effective following the satisfaction of all relevant conditions, including the completion of the proceedings discussed above, DPL continues to believe that it may be required to record its proportional share of the contracts as derivative instruments at fair value and record related regulatory assets of approximately the same amount because it would be entitled to recover any payments under the contracts from SOS customers. DPL has concluded that any accounting for these contracts would not be required until all legal proceedings related to these contracts and the actions of the MPSC in the related proceeding have been resolved. Merger Approval Proceedings Delaware On June 18, 2014, Exelon, PHI and DPL, and certain of their respective affiliates, filed an application with the DPSC seeking approval of the Merger. Delaware law requires the DPSC to approve the Merger when it determines that the transaction is in accordance with law, for a proper purpose, and is consistent with the public interest. The DPSC must further find that the successor will continue to provide safe and reliable service, will not terminate or impair existing collective bargaining agreements and will engage in good faith bargaining with organized labor. On February 13, 2015, Exelon, DPL, the DPSC staff, the Division of the Public Advocate and certain other parties filed a settlement agreement with the DPSC, which was amended in April 2015. The DPSC approved the amended settlement agreement at its meeting held on May 19, 2015, memorializing this decision by written order issued on June 2, 2015. The specific grounds for the DPSC’s approval of the Merger, as well as the specific conditions, will be included in an order to be issued by the DPSC after the Merger closes. Maryland On August 19, 2014, Exelon, PHI, Pepco, DPL and certain of their respective affiliates, filed an application with the MPSC seeking approval of the Merger. Maryland law requires the MPSC to approve a merger subject to its review if it finds that the merger is consistent with the public interest, convenience and necessity, including its benefits to and impact on consumers. Evidentiary hearings were held beginning on January 26, 2015. On March 10, 2015, Exelon, PHI, Pepco, DPL and certain of their respective affiliates, filed with the MPSC a settlement agreement entered into with one of the stakeholder groups participating in the MPSC approval proceeding. On March 16, 2015, Exelon, PHI, Pepco, DPL and certain of their respective affiliates, filed with the MPSC a settlement agreement entered into with Montgomery and Prince George’s Counties in Maryland, and a number of other parties. On May 15, 2015, the MPSC approved the Merger, with conditions, including conditions that modify and supplement those originally proposed. On May 18, 2015, Pepco Holdings and Exelon announced that they had completed their review of the MPSC’s order approving the Merger and have committed to fulfill the modified, more stringent conditions and package of customer benefits imposed by the MPSC. Multiple parties have filed petitions for judicial review of the MPSC order by the Circuit Court of Queen Anne’s County, Maryland, seeking to appeal the MPSC order. In connection with these proceedings, the Maryland Office of People’s Counsel and several other parties to the Merger proceedings filed motions in the Circuit Court for Queen Anne’s County, Maryland, requesting a stay of the MPSC order. On August 7, 2015, the Circuit Court for Queen Anne’s County denied the motions for stay. On January 8, 2016, the Circuit Court affirmed the MPSC’s order in all respects. On January 20 and 22, 2016, respectively, the Maryland Office of People’s Counsel and environmental groups filed notices of appeal of the Circuit Court’s order to the Maryland Court of Special Appeals. Unless a motion to stay is filed and then granted by the court, the MPSC order will remain in effect during the appeals process. Virginia On June 3, 2014, Exelon, PHI, Pepco and DPL, and certain of their respective affiliates, filed an application with the VSCC seeking approval of the Merger. Virginia law provides that, if the VSCC determines, with or without hearing, that adequate service to the public at just and reasonable rates will not be impaired or jeopardized by granting the application for approval, then the VSCC shall approve a merger with such conditions that the VSCC deems to be appropriate in order to satisfy this standard. On October 7, 2014, the VSCC issued an order approving the Merger. Federal Energy Regulatory Commission On May 30, 2014, Exelon, PHI, Pepco, DPL and ACE, and certain of their respective affiliates, submitted to FERC a Joint Application for Authorization of Disposition of Jurisdictional Assets and Merger under Section 203 of the Federal Power Act. Under that section, FERC shall approve a merger if it finds that the proposed transaction will be consistent with the public interest. On November 20, 2014, FERC issued an order approving the Merger. |
Atlantic City Electric Co [Member] | |
Regulatory Matters | (6) REGULATORY MATTERS Regulatory Assets and Regulatory Liabilities The components of ACE’s regulatory asset and liability balances at December 31, 2015 and 2014 are as follows: 2015 2014 (millions of dollars) Regulatory Assets Securitized stranded costs $ 202 $ 278 Recoverable income taxes 44 42 Deferred energy supply costs 27 58 Incremental storm restoration costs 18 15 Deferred debt extinguishment costs 7 8 Other 24 26 Total Regulatory Assets $ 322 $ 427 Regulatory Liabilities Federal and state tax benefits, related to securitized stranded costs $ 13 $ 8 Reserves for FERC ROE transmission challenges 8 1 Deferred income taxes due to customers 3 3 Other 3 2 Total Regulatory Liabilities $ 27 $ 14 A description for each category of regulatory assets and regulatory liabilities follows: Securitized Stranded Costs: Recoverable Income Taxes: Deferred Energy Supply Costs: Incremental Storm Restoration Costs: Deferred Debt Extinguishment Costs: Other: Federal and State Tax Benefits, Related to Securitized Stranded Costs: Reserves for FERC ROE Transmission Challenges Deferred Income Taxes Due to Customers: Other: Rate Proceedings As further described in Note (1), “Organization,” on April 29, 2014, PHI entered into the Merger Agreement with Exelon and Merger Sub. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, PHI and its subsidiaries may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than pursuing the conclusion of certain proceedings, as described below. To date, ACE has not requested such consent from Exelon and has not filed any new distribution base rate cases since entering into the Merger Agreement. Bill Stabilization Adjustment Although ACE proposed the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers, this decoupling proposal has not to date been adopted. New Jersey Update and Reconciliation of Certain Under-Recovered Balances In March 2015, ACE submitted its 2015 annual petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the NUGs, and (ii) costs related to surcharges for the New Jersey Societal Benefit Program (a statewide public interest program that is intended to benefit low income customers and address other public policy goals) and for ACE’s uncollected accounts. As filed, the net impact of the proposed changes would have been an annual rate increase of approximately $52.0 million (revised to an increase of approximately $33.9 million on April 17, 2015, based upon updates for actual data through March 31, 2015). On May 19, 2015, the NJBPU approved a stipulation of settlement entered into by the parties providing for a provisional overall annual rate increase of $33.9 million effective June 1, 2015. On September 11, 2015, the NJBPU approved a stipulation of settlement in this proceeding, which made final the provisional rates that were placed into effect as of June 1, 2015, with an adjustment that decreased the rate applicable to the residential class by $1.3 million. This rate increase of approximately $32.6 million will have no effect on ACE’s operating income, since these revenues provide for recovery of deferred costs under an approved deferral mechanism. On February 1, 2016, ACE submitted its 2016 annual petition with the NJBPU seeking to reconcile and update the same categories of charges and costs described in (i) and (ii) in the above paragraph. The net impact of adjusting the charges as proposed is an overall annual rate increase of approximately $8.8 million, including New Jersey Sales and Use Tax. The matter is pending at the NJBPU and will be updated for January through March 2016 actual data. ACE has requested that the NJBPU place the new rates into effect by June 1, 2016. Service Extension Contributions Refund Order In July 2013, in compliance with a 2012 Superior Court of New Jersey Appellate Division (Appellate Division) court decision, the NJBPU released an order requiring utilities to issue refunds to persons or entities that paid non-refundable contributions for utility service extensions to certain areas described as “Areas Not Designated for Growth.” The order is limited to eligible contributions paid between March 20, 2005 and December 20, 2009. ACE is processing the refund requests that meet the eligibility criteria established in the order as they are received. Although ACE estimates that it received approximately $11 million of contributions between March 20, 2005 and December 20, 2009, it is currently unable to reasonably estimate the amount that it may be required to refund using the eligibility criteria established by the order. Since the July 2013 order was released, ACE has paid less than $1 million in refund claims, the validity of each of which is investigated by ACE prior to making any such refunds. In September 2014, the NJBPU commenced a rulemaking proceeding to further implement the directives of the Appellate Division decision. In November 2015, the NJBPU adopted new regulations that remove provisions distinguishing between growth areas and not-for-growth areas and provide formulae for allocating extension costs. At this time, ACE does not expect the amount it is ultimately required to refund will have a material effect on its consolidated financial condition, results of operations or cash flows, as the amount refunded will generally increase the value of ACE’s property, plant and equipment and may ultimately be recovered through depreciation expense and cost of service in future electric distribution base rate cases. Generic Consolidated Tax Adjustment Proceeding In January 2013, the NJBPU initiated a generic proceeding to examine whether a consolidated tax adjustment (CTA) should continue to be used, and if so, how it should be calculated in determining a utility’s cost of service. Under the NJBPU’s current policy, when a New Jersey utility is included in a consolidated group income tax return, an allocated amount of any reduction in the consolidated group’s taxes as a result of losses by affiliates is used to reduce the utility’s rate base, upon which the utility earns a return. This policy has negatively impacted ACE’s electric distribution base rate case outcomes and ACE’s position is that the CTA should be eliminated. In an order issued in October 2014, the NJBPU determined that it is appropriate for affected consolidated groups to continue to include a CTA in New Jersey base rate filings, but that the CTA calculation will be modified to limit the look-back period for the calculation to five years, exclude transmission assets from the calculation, and allocate 25 percent of the final CTA amount as a reduction to the distribution revenue requirement. ACE anticipates that this revised methodology will significantly reduce the negative effects of the CTA in future base rate cases. In November 2014, the New Jersey Division of Rate Counsel filed an appeal of the NJBPU’s CTA order in the Appellate Division. No stay of the October 2014 CTA order was requested in connection with the appeal. As such, barring an adverse finding by the Appellate Division, the order is in effect. The appeal remains pending. FERC Transmission ROE Challenges In February 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as the Delaware Municipal Electric Corporation, Inc., filed a joint complaint at FERC against ACE and its affiliates, Pepco and Delmarva Power & Light Company (DPL), as well as Baltimore Gas and Electric Company (BGE). The complainants challenged the base ROE and certain protocols regarding the formula rate process associated with the transmission service that the utilities provide. The complainants support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for PHI’s utilities is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. The 10.8% base ROE for facilities placed into service prior to 2006 receives a 50-basis-point incentive adder for being a member of a regional transmission organization. In August 2014, FERC issued an order setting the matters in this proceeding for hearing, but holding the hearing in abeyance pending settlement discussions. The order also (i) directed that the evidence and analysis presented concerning ROE be guided by the new ROE methodology adopted by FERC in another proceeding (discussed below), and (ii) set a 15-month refund period that commenced on February 27, 2013, should a refund result from this proceeding. After settlement discussions among the parties in this matter reached an impasse, the settlement judge, in November 2014, issued an order terminating the settlement discussions and referring the matter to a presiding administrative law judge. In June 2014, FERC issued an order in a proceeding in which ACE was not involved, in which it adopted a new ROE methodology for electric utilities. This new methodology replaces the existing one-step discounted cash flow analysis (which incorporates only short-term growth rates) traditionally used to derive ROE for electric utilities with the two-step discounted cash flow analysis (which incorporates both short-term and long-term measures of growth) used for natural gas and oil pipelines. As a result of the August 2014 FERC order discussed in the preceding paragraph, ACE applied an estimated ROE based on the two-step methodology announced by FERC for the 15-month period over which its transmission revenues would be subject to refund as a result of the challenge, and recorded estimated reserves for the entire 15-month refund period in the second quarter of 2014. On December 8, 2014, the parties that filed the February 2013 complaint filed a second complaint against Pepco, DPL, ACE, as well as BGE, regarding the base transmission ROE, seeking a reduction from 10.8% to 8.8%. By order issued on February 9, 2015, FERC established a hearing on the second complaint and established a second 15-month refund period that commenced on December 8, 2014. Consistent with the prior challenge, ACE applied an estimated ROE based on the two-step methodology described above, and in the fourth quarter of 2014 and in the first, second and third quarters of 2015 established reserves for the estimated refund based on the effective date of the second refund period of December 8, 2014. On February 20, 2015, the chief judge issued an order consolidating the two complaint proceedings and established an initial decision issuance deadline of February 29, 2016. On March 2, 2015, the presiding administrative law judge issued an order establishing a procedural schedule for the consolidated proceedings that provided for the hearing to commence on October 20, 2015. Also during the third quarter of 2015, ACE further evaluated the reserves established for each of the two refund periods and, based on an updated assessment of market conditions, developments in other cases before FERC, litigation risk and other factors, increased its reserves to reflect management’s best estimate of the refund that is expected to result from these consolidated proceedings. A settlement entered into by the parties regarding the protocols (but not the ROE) raised in the February 2013 complaint was submitted to FERC on July 31, 2015 and was approved by FERC in November 2015. On November 6, 2015, the parties filed a settlement agreement with FERC regarding the ROE. This settlement agreement provides for (i) a base ROE of 10.0%, effective March 8, 2016, to which a 50-basis-point incentive adder will be applied for being a member of a regional transmission organization, and (ii) customer refunds in the amount of approximately $9.5 million for ACE covering the two 15-month refund periods described above. In addition, under this settlement agreement, no party may file to change the base ROE or any incentives prior to June 1, 2018. The parties have requested that FERC approve this settlement agreement by March 16, 2016, in order to incorporate the new ROE and applicable refunds into each utility’s 2016 transmission formula rate update. As of December 31, 2015, ACE’s reserves for both of the refund periods totaled $8 million as required under the settlement agreement. ACE Standard Offer Capacity Agreements In April 2011, ACE entered into three Standard Offer Capacity Agreements (SOCAs) by order of the NJBPU, each with a different generation company. ACE entered into the SOCAs under protest, as did the other electric distribution companies (EDCs) in New Jersey, arguing that the EDCs were denied due process and that the SOCAs violated certain of the requirements of the New Jersey law under which the SOCAs were established (the NJ SOCA Law). In October 2013, in light of the decision of the U.S. District Court for the District of New Jersey described below, the state appeals of the NJBPU implementation orders filed by the EDCs and generators were dismissed without prejudice, subject to the parties exercising their appellate rights in the Federal courts. In February 2011, ACE joined other plaintiffs in an action filed in the U.S. District Court for the District of New Jersey challenging the NJ SOCA Law on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In October 2013, the Federal district court ruled that the NJ SOCA Law is preempted by the Federal Power Act (FPA) and violates the Supremacy Clause, and is therefore null and void. In October 2013, the Federal district court issued an order ruling that the SOCAs are void, invalid and unenforceable, which order was affirmed by the U.S. Court of Appeals for the Third Circuit in September 2014. In November 2014 and December 2014, respectively, one of the generation companies and the NJBPU petitioned the U.S. Supreme Court to consider hearing an appeal of the Third Circuit decision. The U.S. Supreme Court has not yet agreed to review the Third Circuit decision and the petitions for such review remain pending. ACE terminated one of the three SOCAs effective July 1, 2013 due to the occurrence of an event of default on the part of the generation company counterparty. ACE terminated the remaining two SOCAs effective November 19, 2013, in response to the October 2013 Federal district court decision. In response to the October 2013 Federal district court order, ACE, in the fourth quarter of 2013, derecognized both the derivative assets (liabilities) for the estimated fair value of the SOCAs and the related regulatory liabilities (assets) that it had established with respect to the SOCAs. Merger Approval Proceedings New Jersey On June 18, 2014, Exelon, PHI and ACE, and certain of their respective affiliates, filed a petition with the NJBPU seeking approval of the Merger. To approve the Merger, the NJBPU must find the Merger is in the public interest, and consider the impact of the Merger on (i) competition, (ii) rates of ratepayers affected by the Merger, (iii) ACE’s employees, and (iv) the provision of safe and reliable service at just and reasonable rates. On January 14, 2015, PHI, ACE, Exelon, certain of Exelon’s affiliates, the Staff of the NJBPU, and the Independent Energy Producers of New Jersey filed a stipulation of settlement (the Stipulation) with the NJBPU in this proceeding. On February 11, 2015, the NJBPU approved the Stipulation and the Merger and on March 6, 2015, the NJBPU issued a written order approving the Stipulation. The NJBPU order states that the Merger must be closed by November 1, 2015 unless extended by the NJBPU. On October 15, 2015, the NJBPU voted to extend the effectiveness of its Merger approval until June 30, 2016. Federal Energy Regulatory Commission On May 30, 2014, Exelon, PHI, Pepco, DPL and ACE, and certain of their respective affiliates, submitted to FERC a Joint Application for Authorization of Disposition of Jurisdictional Assets and Merger under Section 203 of the FPA. Under that section, FERC shall approve a merger if it finds that the proposed transaction will be consistent with the public interest. On November 20, 2014, FERC issued an order approving the Merger. |
Property, Plant and Equipment
Property, Plant and Equipment | 12 Months Ended |
Dec. 31, 2015 | |
Property, Plant and Equipment | (8) PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment is comprised of the following: Original Cost Accumulated Net Book Value (millions of dollars) At December 31, 2015 Generation $ 23 $ 19 $ 4 Distribution 10,051 3,161 6,890 Transmission 3,554 962 2,592 Gas 546 163 383 Construction work in progress 604 — 604 Non-operating and other property 1,440 609 831 Total $ 16,218 $ 4,914 $ 11,304 At December 31, 2014 Generation $ 104 $ 100 $ 4 Distribution 9,527 3,021 6,506 Transmission 3,252 934 2,318 Gas 511 153 358 Construction work in progress 688 — 688 Non-operating and other property 1,383 751 632 Total $ 15,465 $ 4,959 $ 10,506 The non-operating and other property amounts include balances for general plant, intangible plant, distribution plant and transmission plant held for future use as well as other property held by non-utility subsidiaries. Utility plant is generally subject to a first mortgage lien. Pepco Holdings’ utility subsidiaries use separate depreciation rates for each electric plant account. The rates vary from jurisdiction to jurisdiction. Jointly Owned Plant PHI’s consolidated balance sheets include its proportionate share of assets and liabilities related to jointly owned plant. At December 31, 2015 and 2014, PHI’s subsidiaries had a net book value ownership interest of $16 million and $15 million, respectively, in transmission and other facilities in which various parties also have ownership interests. PHI’s share of the operating and maintenance expenses of the jointly owned plant is included in the corresponding expenses in the consolidated statements of income (loss). PHI is responsible for providing its share of the financing for the above jointly owned facilities. Capital Leases Pepco leases its consolidated control center, which is an integrated energy management center used by Pepco to centrally control the operation of its transmission and distribution systems. This lease is accounted for as a capital lease and was initially recorded at the present value of future lease payments, which totaled $152 million. The lease requires semi-annual payments of approximately $8 million over a 25-year period that began in December 1994, and provides for transfer of ownership of the system to Pepco for $1 at the end of the lease term. Under FASB guidance on regulated operations, the amortization of leased assets is modified so that the total interest expense charged on the obligation and amortization expense of the leased asset is equal to the rental expense allowed for rate-making purposes. The amortization expense is included within Depreciation and amortization in the consolidated statements of income (loss). This lease is treated as an operating lease for rate-making purposes. Capital lease assets recorded within Property, Plant and Equipment at December 31, 2015 and 2014 are comprised of the following: Original Accumulated Amortization Net Book Value (millions of dollars) At December 31, 2015 Transmission $ 76 $ 51 $ 25 Distribution 76 51 25 Total $ 152 $ 102 $ 50 At December 31, 2014 Transmission $ 76 $ 46 $ 30 Distribution 76 46 30 Total $ 152 $ 92 $ 60 The approximate annual commitments under all capital leases are $15 million in each of the years 2016 through 2018 and $16 million in 2019. Gains on Sales of Land Since 2002, Pepco has owned a 3.5 acre parcel of unimproved land (held as non-utility property) in the Buzzard Point area of southeast Washington, D.C. On July 2, 2015, Pepco entered into a purchase and sale agreement with the District of Columbia to sell the 3.5-acre parcel with a carrying value of $2 million at a purchase price of $39 million. The transaction was consummated on November 10, 2015 resulting in a $37 million pre-tax gain ($22 million after-tax) which was recorded in the fourth quarter of 2015. Since 2003, Pepco has owned a 3.8 acre parcel of unimproved land (held as non-utility property) in the NoMa area of northeast Washington, D.C. On October 16, 2015, Pepco entered into a purchase and sale agreement with a third party to sell a two-acre parcel of the unimproved land with an allocated carrying value of $5 million at a purchase price of $14 million. The transaction was consummated on December 31, 2015 resulting in a $9 million pre-tax gain ($5 million after-tax) which was recorded in the fourth quarter of 2015. The purchase and sale agreement also provided the third party with a 90-day option to purchase the remaining 1.8-acre land parcel with an allocated carrying value of $4 million at a purchase price of $13 million. Deactivation of Pepco Energy Services’ Generating Facilities During 2012, Pepco Energy Services deactivated its Buzzard Point and Benning Road oil-fired generation facilities. Pepco Energy Services completed demolition of the Benning Road generation facility in July 2015 and recognized the scrap metal salvage value of the facility as a reduction in its demolition expenses over the life of the project. Long-Lived Asset Impairment During 2014, PHI recorded impairment losses of $81 million ($48 million after-tax) at Pepco Energy Services associated with its combined heat and power thermal generating facilities and operations in Atlantic City, which reduced the carrying amount of its long lived assets in Atlantic City from $83 million to $2 million at December 31, 2014. PHI performed long-lived asset impairment tests on asset groups comprising substantially all of the long-lived assets in Atlantic City as a result of significant adverse changes in the financial condition of its customers and the business climate in Atlantic City. The assets were written down to their estimated fair values because the future estimated undiscounted cash flows from the asset groups were significantly lower than their carrying value. PHI estimated the fair values of the asset groups from a market participant’s perspective by calculating the present value of estimated future cash flows over the useful lives of the assets using an appropriate discount rate. Both the estimated future cash flows and the discount rate were based on primarily unobservable, Level 3 inputs. The estimated future cash flows were probability weighted based on several potential outcomes regarding forecasted revenues and expenses associated with each asset group. Forecasted revenues and expenses were, in part, based on estimated future commodity prices from an external valuation specialist. In addition, PHI forecasted customer usage volumes and the associated operations and maintenance expenses and capital expenditures. A 10 percent change in the estimated cash flows would not have a significant impact on the estimated fair value of the assets. PHI also selected a discount rate that would reflect a market return on the estimated cash flows. PHI considered a range of discount rates between 10 percent and 16 percent. A one percent change in the discount rate assumptions would not have a significant impact on the estimated fair value of the assets. During 2013, PHI recorded impairment losses of $4 million ($3 million after-tax) at Pepco Energy Services associated primarily with its investments in landfill gas-fired electric generation facilities. PHI performed a long-lived asset impairment test on the landfill generation facilities of Pepco Energy Services as a result of a sustained decline in energy prices and recent production levels. The asset value of the facilities was written down to the estimated fair value because the future expected cash flows of the facilities were not sufficient to provide recovery of the facilities’ carrying value. PHI estimated the fair value of the facilities by calculating the present value of expected future cash flows using an appropriate discount rate. Both the expected future cash flows and the discount rate used primarily unobservable inputs. Asset Retirement Obligations PHI recognizes liabilities related to the retirement of long-lived assets in accordance with ASC 410. As of December 31, 2015, PHI had an asset retirement obligation of $7 million on its consolidated balance sheet related to the Edge Moor coal ash landfill site. The asset retirement obligation reflects estimates of the costs for PHI to close the landfill and provide post-closure operations, maintenance and monitoring services. |
Potomac Electric Power Co [Member] | |
Property, Plant and Equipment | (7) PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment is comprised of the following: Original Accumulated Depreciation Net Book (millions of dollars) At December 31, 2015 Distribution $ 5,996 $ 2,199 $ 3,797 Transmission 1,378 475 903 Construction work in progress 318 — 318 Non-operating and other property 399 125 274 Total $ 8,091 $ 2,799 $ 5,292 At December 31, 2014 Distribution $ 5,668 $ 2,082 $ 3,586 Transmission 1,306 463 843 Construction work in progress 312 — 312 Non-operating and other property 478 271 207 Total $ 7,764 $ 2,816 $ 4,948 The non-operating and other property amounts include balances for general plant, distribution plant and transmission plant held for future use, intangible plant and non-utility property. Utility plant is generally subject to a first mortgage lien. Capital Leases Pepco leases its consolidated control center, which is an integrated energy management center used by Pepco to centrally control the operation of its transmission and distribution systems. This lease is accounted for as a capital lease and was initially recorded at the present value of future lease payments, which totalled $152 million. The lease requires semi-annual payments of approximately $8 million over a 25-year period that began in December 1994, and provides for transfer of ownership of the system to Pepco for $1 at the end of the lease term. Under FASB guidance on regulated operations, the amortization of leased assets is modified so that the total interest expense charged on the obligation and amortization expense of the leased asset is equal to the rental expense allowed for rate-making purposes. The amortization expense is included within Depreciation and amortization in the statements of income. This lease is treated as an operating lease for rate-making purposes. Capital lease assets recorded within Property, plant and equipment at December 31, 2015 and 2014 are comprised of the following: Original Accumulated Amortization Net Book (millions of dollars) At December 31, 2015 Transmission $ 76 $ 51 $ 25 Distribution 76 51 25 Total $ 152 $ 102 $ 50 At December 31, 2014 Transmission $ 76 $ 46 $ 30 Distribution 76 46 30 Total $ 152 $ 92 $ 60 The approximate annual commitments under all capital leases are $15 million in each of the years 2016 through 2018 and $16 million in 2019. Gains on Sales of Land Since 2002, Pepco has owned a 3.5 acre parcel of unimproved land (held as non-utility property) in the Buzzard Point area of southeast Washington, D.C. On July 2, 2015, Pepco entered into a purchase and sale agreement with the District of Columbia to sell the 3.5-acre parcel with a carrying value of $2 million at a purchase price of $39 million. The transaction was consummated on November 10, 2015 resulting in a $37 million pre-tax gain ($22 million after-tax) which was recorded in the fourth quarter of 2015. Since 2003, Pepco has owned a 3.8 acre parcel of unimproved land (held as non-utility property) in the NoMa area of northeast Washington, D.C. On October 16, 2015, Pepco entered into a purchase and sale agreement with a third party to sell a two-acre parcel of the unimproved land with an allocated carrying value of $5 million at a purchase price of $14 million. The transaction was consummated on December 31, 2015 resulting in a $9 million pre-tax gain ($5 million after-tax) which was recorded in the fourth quarter of 2015. The purchase and sale agreement also provided the third party with a 90-day option to purchase the remaining 1.8-acre land parcel with an allocated carrying value of $4 million at a purchase price of $13 million. |
Delmarva Power & Light Co/De [Member] | |
Property, Plant and Equipment | (8) PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment is comprised of the following: Original Cost Accumulated Depreciation Net Book Value (millions of dollars) At December 31, 2015 Distribution $ 2,043 $ 490 $ 1,553 Transmission 1,208 259 949 Gas 546 163 383 Construction work in progress 107 — 107 Non-operating and other property 305 134 171 Total $ 4,209 $ 1,046 $ 3,163 At December 31, 2014 Distribution $ 1,928 $ 489 $ 1,439 Transmission 1,107 248 859 Gas 511 153 358 Construction work in progress 125 — 125 Non-operating and other property 275 131 144 Total $ 3,946 $ 1,021 $ 2,925 The non-operating and other property amounts include balances for general plant, plant held for future use, intangible plant and non-utility property. Utility plant is generally subject to a first mortgage lien. |
Atlantic City Electric Co [Member] | |
Property, Plant and Equipment | (7) PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment is comprised of the following: Original Cost Accumulated Net Book Value (millions of dollars) At December 31, 2015 Distribution $ 2,012 $ 472 $ 1,540 Transmission 968 228 740 Construction work in progress 158 — 158 Non-operating and other property 167 64 103 Total $ 3,305 $ 764 $ 2,541 At December 31, 2014 Generation $ 10 $ 9 $ 1 Distribution 1,931 450 1,481 Transmission 839 223 616 Construction work in progress 115 — 115 Non-operating and other property 178 78 100 Total $ 3,073 $ 760 $ 2,313 The non-operating and other property amounts include balances for general plant, plant held for future use, intangible plant and non-utility property. Utility plant is generally subject to a first mortgage lien. Jointly Owned Plant ACE’s consolidated balance sheets include its proportionate share of assets and liabilities related to jointly owned plant. At each of December 31, 2015 and 2014, ACE’s subsidiaries had a net book value ownership interest of $11 million in transmission and other facilities in which various parties also have ownership interests. ACE’s share of the operating and maintenance expenses of the jointly owned plant is included in the corresponding expenses in the consolidated statements of income. ACE is responsible for providing its share of the financing for the above jointly owned facilities. |
Pension and Other Postretiremen
Pension and Other Postretirement Benefits | 12 Months Ended |
Dec. 31, 2015 | |
Pension and Other Postretirement Benefits | (9) PENSION AND OTHER POSTRETIREMENT BENEFITS The following table shows changes in the benefit obligation and plan assets for the years ended December 31, 2015 and 2014: Pension Benefits Other Postretirement 2015 2014 2015 2014 (millions of dollars) Change in Benefit Obligation Benefit obligation as of January 1 $ 2,638 $ 2,238 $ 632 $ 574 Service cost 57 44 7 7 Interest cost 109 109 24 26 Actuarial loss (gain) (151 ) 401 (61 ) 59 Benefits paid (163 ) (154 ) (39 ) (34 ) Benefit obligation as of December 31 $ 2,490 $ 2,638 $ 563 $ 632 Change in Plan Assets Fair value of plan assets as of January 1 $ 2,236 $ 2,116 $ 367 $ 368 Actual return on plan assets (61 ) 268 1 21 Company and participant contributions 6 6 5 6 Benefits paid by plan (163 ) (154 ) (25 ) (28 ) Fair value of plan assets as of December 31 $ 2,018 $ 2,236 $ 348 $ 367 Funded Status at end of year (plan assets less plan obligations) $ (472 ) $ (402 ) $ (215 ) $ (265 ) At December 31, 2015 and 2014, the PHI Retirement Plan’s accumulated benefit obligation was approximately $2.3 billion and $2.4 billion, respectively. The accumulated benefit obligation differs from the pension benefit obligation presented in the table above in that the accumulated benefit obligation includes no assumption about future compensation levels. The following table provides the amounts recorded in PHI’s consolidated balance sheets as of December 31, 2015 and 2014: Pension Benefits Other Postretirement 2015 2014 2015 2014 (millions of dollars) Regulatory asset $ 870 $ 871 $ 40 $ 75 Current liabilities (6 ) (6 ) — — Pension benefit obligation (466 ) (396 ) — — Other postretirement benefit obligations — — (215 ) (265 ) Deferred income tax liabilities (162 ) (193 ) 70 77 Accumulated other comprehensive loss, net of tax 28 37 — — Net amount recorded $ 264 $ 313 $ (105 ) $ (113 ) Amounts included in AOCL (pre-tax) and Regulatory assets at December 31, 2015 and 2014 consist of: Pension Other Postretirement 2015 2014 2015 2014 (millions of dollars) Unrecognized net actuarial loss $ 910 $ 925 $ 128 $ 176 Unamortized prior service cost (credit) 6 8 (88 ) (101 ) Total $ 916 $ 933 $ 40 $ 75 Accumulated other comprehensive loss ($28 million and $37 million, net of tax, at December 31, 2015 and 2014, respectively) $ 46 $ 62 $ — $ — Regulatory assets 870 871 40 75 Total $ 916 $ 933 $ 40 $ 75 Under FASB guidance on regulated operations, a portion of actuarial gains and losses and prior service costs (credits) are included in Regulatory assets (liabilities) in the consolidated balance sheets to reflect expected regulatory recovery of such amounts, which otherwise would be recorded to AOCL. The table below provides the changes in plan assets and benefit obligations recognized in AOCL and Regulatory assets for the years ended December 31, 2015, 2014 and 2013: Pension Benefits Other Postretirement 2015 2014 2013 2015 2014 2013 (millions of dollars) Amounts amortized during the year: Amortization of prior service (cost) credit $ (2 ) $ (2 ) $ (2 ) $ 13 $ 13 $ 11 Amortization of net actuarial loss (65 ) (45 ) (67 ) (8 ) (3 ) (12 ) Amounts arising during the year: Current year prior service cost (credit) — — 3 — — (124 ) Current year actuarial loss (gain) 50 276 (218 ) (39 ) 62 (109 ) Total recognized in AOCL and Regulatory assets for the year ended December 31 $ (17 ) $ 229 $ (284 ) $ (34 ) $ 72 $ (234 ) The estimated net actuarial loss and prior service cost for the defined benefit pension plans that will be amortized from AOCL or Regulatory assets into net periodic benefit cost over the next reporting year are $63 million and $1 million, respectively. The estimated net actuarial loss and prior service credit for the OPEB plan that will be amortized from AOCL or Regulatory assets into net periodic benefit cost over the next reporting year are $7 million and $13 million, respectively. The table below provides the components of net periodic benefit costs recognized for the years ended December 31, 2015, 2014 and 2013: Pension Benefits Other Postretirement 2015 2014 2013 2015 2014 2013 (millions of dollars) Service cost $ 57 $ 44 $ 53 $ 7 $ 7 $ 8 Interest cost 109 109 100 24 26 29 Expected return on plan assets (140 ) (141 ) (145 ) (22 ) (24 ) (20 ) Amortization of prior service cost (credit) 2 2 2 (13 ) (13 ) (11 ) Amortization of net actuarial loss 65 45 67 8 3 12 Net periodic benefit cost $ 93 $ 59 $ 77 $ 4 $ (1 ) $ 18 The table below provides the split of the combined pension and other postretirement net periodic benefit costs among subsidiaries for the years ended December 31, 2015, 2014 and 2013: 2015 2014 2013 (millions of dollars) Pepco $ 30 $ 22 $ 34 DPL 15 7 18 ACE 15 13 17 Other subsidiaries 37 16 26 Total $ 97 $ 58 $ 95 The following weighted average assumptions were used to determine the benefit obligations at December 31, 2015 and 2014: Pension Benefits Other Postretirement 2015 2014 2015 2014 Discount rate 4.65% /4.55 % (a) 4.20 % 4.55 % 4.15 % Rate of compensation increase 5.00 % 5.00 % 5.00 % 5.00 % Health care cost trend rate assumed for current year – pre 65 — — 6.33 % 6.67 % Health care cost trend rate assumed for current year – post 65 — — 5.40 % 5.50 % Rate to which the cost trend rate is assumed to decline for all eligible retirees (the ultimate trend rate) — — 5.00 % 5.00 % Year that the cost trend rate reaches the ultimate trend rate — — 2020 2020 (a) The discount rate for the qualified and nonqualified pension plans was 4.65% and 4.55%, respectively. Assumed health care cost trend rates may have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects, in millions of dollars: 1-Percentage- Point Increase 1-Percentage- Point Decrease Increase (decrease) in total service and interest cost $ 1 $ (1 ) Increase (decrease) in postretirement benefit obligation $ 15 $ (18 ) The following weighted average assumptions were used to determine the net periodic benefit cost for the years ended December 31, 2015, 2014 and 2013: Pension Benefits Other Postretirement Benefits 2015 2014 2013 2015 2014 2013 Discount rate 4.20 % 5.05 % 4.15 % 4.15 % 5.00 % 4.10%/4.95 % (a) Expected long-term return on plan assets 6.50 % 7.00 % 7.00 % 6.75 % 7.25 % 7.00 % Rate of compensation increase 5.00 % 5.00 % 5.00 % 5.00 % 5.00 % 5.00 % Health care cost trend rate — — — 6.67 % 7.00 % 7.50 % (a) The discount rate was updated for remeasurement to 4.95% on July 1, 2013. PHI utilizes an analytical tool developed by its actuaries to select the discount rate. The analytical tool utilizes a high-quality bond portfolio with cash flows that match the benefit payments expected to be made under the plans. PHI uses a building block approach to estimate the expected rate of return on plan assets. Under this approach, the percentage of plan assets in each asset class according to PHI’s target asset allocation, at the beginning of the year, is applied to the expected asset return for the related asset class. PHI incorporates long-term assumptions for real returns, inflation expectations, volatility and correlations among asset classes to determine expected returns for a given asset allocation. The pension and postretirement benefit plan assets consist of equity, fixed income, real estate and private equity investments. PHI periodically reviews its asset mix and rebalances assets to the target allocation. The average remaining service periods for participating employees of the benefit plans was approximately 11 years for both 2015 and 2014. PHI utilizes plan census data to estimate these average remaining service periods. PHI uses mortality tables and mortality improvement scales issued by the Society of Actuaries to estimate participants’ life expectancy. In 2014, the Society of Actuaries issued updated mortality tables and mortality improvement scales which PHI applied in determining its benefit obligations as of December 31, 2014. In 2015, the Society of Actuaries modified the tables issued in 2014 to reflect updated mortality improvement experience. PHI applied these modified tables in determining its benefit obligations as of December 31, 2015. Benefit Plan Modifications During 2013, PHI approved two amendments to its other postretirement benefits plan. These amendments impacted the retiree health care and the retiree life insurance benefits, and were effective on January 1, 2014. As a result of the amendments, which were cumulatively significant, PHI remeasured its accumulated postretirement benefit obligation for other postretirement benefits as of July 1, 2013. The remeasurement resulted in a $193 million reduction of the accumulated postretirement benefit obligation, which included recording a prior service credit of $124 million, which will be amortized over approximately ten years, and a $69 million reduction from a change in the discount rate from 4.10% as of December 31, 2012 to 4.95% as of July 1, 2013. The remeasurement resulted in a $19 million reduction in net periodic benefit cost for other postretirement benefits during 2014, when compared to 2013. Approximately 36% of net periodic other postretirement benefit costs were capitalized in 2014. Plan Assets Investment Policies and Strategies In developing its allocation policy for the assets in the PHI Retirement Plan and the other postretirement benefit plan, PHI examined projections of asset returns and volatility over a long-term horizon. In connection with this analysis, PHI evaluated the risk and return tradeoffs of alternative asset classes and asset mixes given long-term historical relationships as well as prospective capital market returns. PHI also conducted an asset-liability study to match projected asset growth with projected liability growth to determine whether there is sufficient liquidity for projected benefit payments. PHI developed its asset mix guidelines by incorporating the results of these analyses with an assessment of its risk posture, and taking into account industry practices. PHI periodically evaluates its investment strategy to ensure that plan assets are sufficient to meet the benefit obligations of the plans. As part of the ongoing evaluation, PHI may make changes to its targeted asset allocations and investment strategy. PHI’s pension investment strategy is designed to meet the following investment objectives: • Generate investment returns that, in combination with funding contributions from PHI, provide adequate funding to meet all current and future benefit obligations of the plan, • Provide investment results that meet or exceed the assumed long-term rate of return, while maintaining the funded status of the plan at acceptable levels, • Improve funded status over time, and • Decrease contribution and expense volatility as funded status improves. To achieve these investment objectives, PHI’s investment strategy divides the pension program into two primary portfolios: Return-Seeking Assets Liability-Hedging Assets PHI follows an asset-liability management strategy for PHI Retirement Plan assets in order to reduce the effects of future volatility of the fair value of its pension plan assets relative to its pension plan liabilities. For example, in 2015, this strategy uses a 68% target allocation to fixed income investments, primarily in high quality, longer-maturity fixed income securities. The PHI Retirement Plan asset allocations at December 31, 2015 and 2014, by asset category, were as follows: Asset Category Plan Assets at December 31, Target Plan Asset Allocation 2015 2014 2015 2014 Equity 28 % 28 % 27 % 27 % Fixed Income 66 % 65 % 68 % 68 % Other (real estate, private equity) 6 % 7 % 5 % 5 % Total 100 % 100 % 100 % 100 % PHI’s other postretirement benefit plan asset allocations at December 31, 2015 and 2014, by asset category, were as follows: Asset Category Plan Assets at December 31, Target Plan Asset Allocation 2015 2014 2015 2014 Equity 63 % 64 % 60 % 60 % Fixed Income 34 % 34 % 35 % 35 % Cash 3 % 2 % 5 % 5 % Total 100 % 100 % 100 % 100 % PHI will rebalance the plan asset portfolios when the actual allocations fall outside the ranges outlined in the investment policy or as funded status improves over a reasonable period of time. Risk Management Pension and other postretirement benefit plan assets may be invested in separately managed accounts in which there is ownership of individual securities, shares of commingled funds or mutual funds, or limited partnerships. Commingled funds and mutual funds are subject to detailed policy guidelines set forth in the fund’s prospectus or fund declaration, and limited partnerships are subject to the terms of the partnership agreement. Separate account investment managers are responsible for achieving a level of diversification in their portfolio that is consistent with their investment approach and their role in PHI’s overall investment structure. Separate account investment managers must follow risk management guidelines established by PHI unless authorized in writing by PHI. Derivative instruments are permissible in an investment portfolio to the extent they comply with policy guidelines and are consistent with risk and return objectives. Under no circumstances may such instruments be used speculatively or to leverage the portfolio. Separately managed accounts are prohibited from holding securities issued by the following firms: • PHI and its subsidiaries, • PHI’s pension plan trustee, its parent or its affiliates, • PHI’s pension plan consultant, its parent or its affiliates, and • PHI’s pension plan investment manager, its parent or its affiliates. Fair Value of Plan Assets As defined in the FASB guidance on fair value measurement (ASC 820), fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The FASB’s fair value framework includes a hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3). If the inputs used to measure the financial instruments fall within different levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value measurement of the instrument. Investments are classified within the fair value hierarchy as follows: Level 1: Investments are valued using quoted prices in active markets for identical instruments. Level 2: Investments are valued using other significant observable inputs (e.g., quoted prices for similar investments, interest rates, credit risks, etc). Level 3: Investments are valued using significant unobservable inputs, including internal assumptions. There were no significant transfers between level 1 and level 2 during the years ended December 31, 2015 and 2014. In accordance with new FASB guidance on fair value measurement, certain investments that are measured at fair value using the NAV per share as a practical expedient are no longer classified within the fair value hierarchy and are no longer assigned a level. The fair value measurements table at December 31, 2014, was reclassified to conform to the current year presentation, see Note (3), “Newly Adopted Accounting Standards,” for additional information. The following tables present the fair values of PHI’s pension and other postretirement benefit plan assets by asset category included in and excluded from the fair value hierarchy levels, as of December 31, 2015 and 2014: Fair Value Measurements at December 31, 2015 Total Quoted Prices Significant (Level 2) Significant (Level 3) (millions of dollars) Asset Category Pension Plan Assets: Equity: Domestic (a) $ 311 $ 120 $ 191 $ — International (b) 216 215 — 1 Fixed Income (c) 820 — 810 10 Cash Equivalents (d) 50 50 — — 1,397 $ 385 $ 1,001 $ 11 Investments measured at fair value using net asset value as a practical expedient: Equity: Domestic (a) 33 Fixed Income (c) 504 Other: Private Equity 38 Real Estate 46 Pension Plan Assets Total $ 2,018 Other Postretirement Plan Assets: Equity (e) $ 197 $ 197 $ — $ — Fixed Income (f) 120 120 — — Cash Equivalents 9 9 — — 326 $ 326 $ — $ — Investments measured at fair value using net asset value as a practical expedient: Equity (e) 22 Postretirement Plan Assets Total $ 348 (a) Domestic equity assets predominantly include domestic common stock and commingled funds. (b) International equity assets predominantly include foreign common and preferred stock and warrants. (c) Fixed income assets predominantly include corporate bonds, government bonds, municipal/provincial bonds, collateralized mortgage obligations and commingled funds. (d) Cash equivalents predominantly include cash investments in short-term investment funds. (e) Equity assets include domestic and international commingled funds. (f) Fixed income assets include fixed income commingled funds. Fair Value Measurements at December 31, 2014 Total Quoted Prices Significant (Level 2) Significant (Level 3) (millions of dollars) Asset Category Pension Plan Assets: Equity: Domestic (a) $ 341 $ 128 $ 213 $ — International (b) 255 254 — 1 Fixed Income (c) 916 — 905 11 Cash Equivalents (d) 45 45 — — 1,557 $ 427 $ 1,118 $ 12 Investments measured at fair value using net asset value as a practical expedient: Equity: Domestic (a) 35 Fixed Income (c) 543 Other: Private Equity 47 Real Estate 54 Pension Plan Assets Total $ 2,236 Other Postretirement Plan Assets: Equity (e) $ 208 $ 208 $ — $ — Fixed Income (f) 126 126 — — Cash Equivalents 6 6 — — 340 $ 340 $ — $ — Investments measured at fair value using net asset value as a practical expedient: Equity (e) 27 Postretirement Plan Assets Total $ 367 (a) Domestic equity assets predominantly include domestic common stock and commingled funds. (b) International equity assets predominantly include foreign common and preferred stock and warrants. (c) Fixed income assets predominantly include corporate bonds, government bonds, municipal/provincial bonds, collateralized mortgage obligations and commingled funds. (d) Cash equivalents predominantly include cash investments in short-term investment funds. (e) Equity assets include domestic and international commingled funds. (f) Fixed income assets include fixed income commingled funds. There were no significant concentrations of risk in pension and OPEB plan assets at December 31, 2015 and 2014. Valuation Techniques Used to Determine Fair Value Equity Equity securities are primarily comprised of securities issued by public companies in domestic and foreign markets plus investments in commingled funds, which are valued on a daily basis. PHI can exchange shares of the publicly traded securities and the fair values are primarily sourced from the closing prices on stock exchanges where there is active trading, therefore they would be classified as level 1 investments. If there is less active trading, then the publicly traded securities would typically be priced using observable data, such as bid/ask prices, and these measurements would be classified as level 2 investments. Investments that are not publicly traded and valued using unobservable inputs would be classified as level 3 investments. Investments that are measured at fair value using the NAV per share as a practical expedient are not classified within the fair value hierarchy. Commingled funds with publicly quoted prices and active trading are classified as level 1 investments. For commingled funds that are not publicly traded and have ongoing subscription and redemption activity or have redemption restrictions, the fair value of the investment is the NAV per fund share, derived from the underlying securities’ quoted prices in active markets, and are not classified within the fair value hierarchy. Fixed Income Fixed income investments are primarily comprised of fixed income securities and fixed income commingled funds. The prices for direct investments in fixed income securities are generated on a daily basis. Like the equity securities, fair values generated from active trading on exchanges are classified as level 1 investments. Prices generated from less active trading with wider bid/ask prices are classified as level 2 investments. If prices are based on uncorroborated and unobservable inputs, then the investments are classified as level 3 investments. Investments that are measured at fair value using the NAV per share as a practical expedient are not classified within the fair value hierarchy. Commingled funds with publicly quoted prices and active trading are classified as level 1 investments. For commingled funds that are not publicly traded and have ongoing subscription and redemption activity or redemption restrictions, the fair value of the investment is the NAV per fund share, derived from the underlying securities’ quoted prices in active markets, and are not classified within the fair value hierarchy. Other – Private Equity and Real Estate Investments in private equity and real estate funds are primarily invested in privately held real estate investment properties, trusts and partnerships, as well as equity and debt issued by public or private companies. As a practical expedient, PHI’s interest in the fund or partnership is estimated at NAV. PHI’s interest in these funds cannot be readily redeemed due to the inherent lack of liquidity and the primarily long-term nature of the underlying assets. Distribution is made through the liquidation of the underlying assets. PHI views these investments as part of a long-term investment strategy. These investments are valued by each investment manager based on the underlying assets. The majority of the underlying assets are valued using significant unobservable inputs and often require significant management judgment or estimation based on the best available information. Market data includes observations of the trading multiples of public companies considered comparable to the private companies being valued. The funds utilize valuation techniques consistent with the market, income and cost approaches to measure the fair value of certain real estate investments. In accordance with FASB guidance on fair value measurement, PHI does not classify these investments within the fair value hierarchy. The investments in private equity and real estate funds require capital commitments, which may be called over a specific number of years. Unfunded capital commitments as of December 31, 2015 and 2014 totaled $9 million and $11 million, respectively. Reconciliations of the beginning and ending balances of PHI’s fair value measurements using significant unobservable inputs (level 3) for investments in the pension plan for the years ended December 31, 2015 and 2014 are shown below: Fair Value Measurements Using Significant Unobservable Inputs (Level 3) Equity Fixed Income Total Level 3 (millions of dollars) Balance as of January 1, 2015 $ 1 $ 11 $ 12 Transfer in (out) of Level 3 — — — Purchases — — — Sales — — — Settlements — (1 ) (1 ) Unrealized gain (loss) — — — Realized gain — — — Balance as of December 31, 2015 $ 1 $ 10 $ 11 Fair Value Measurements Using Significant Unobservable Inputs (Level 3) Equity Fixed Income Total Level 3 (millions of dollars) Balance as of January 1, 2014 $ 1 $ 11 $ 12 Transfer in (out) of Level 3 — — — Purchases — — — Sales — — — Settlements — — — Unrealized gain (loss) — — — Realized gain — — — Balance as of December 31, 2014 $ 1 $ 11 $ 12 Cash Flows Contributions - PHI Retirement Plan PHI’s funding policy with regard to the PHI Retirement Plan is to maintain a funding level that is at least equal to the target liability as defined under the Pension Protection Act of 2006, as modified by subsequent legislation. During 2015 and 2014, PHI, Pepco, DPL and ACE did not make any discretionary tax-deductible contributions to the PHI Retirement Plan as its assets met or exceeded the funding target level for 2015 and 2014. Contributions - Other Postretirement Benefit Plan In 2015 and 2014, Pepco contributed $2 million and $1 million, respectively, DPL made no contributions in either year, and ACE contributed $3 million and $3 million, respectively, to the other postretirement benefit plan. In 2015 and 2014, no contributions were made by PHI’s other subsidiaries. Expected Benefit Payments Estimated future benefit payments to participants in PHI’s pension and other postretirement benefit plans, which reflect expected future service as appropriate, are as follows: Years Pension Benefits Other Postretirement (millions of dollars) 2016 $ 143 $ 38 2017 143 38 2018 148 38 2019 153 38 2020 158 38 2021 through 2025 836 189 Pepco Holdings Retirement Savings Plan Pepco Holdings has a defined contribution retirement savings plan. Participation in the plan is voluntary. All participants are 100% vested and have a nonforfeitable interest in their own contributions and in the Pepco Holdings’ company matching contributions, including any earnings or losses thereon. Pepco Holdings’ matching contributions were $14 million, $13 million and $12 million for the years ended December 31, 2015, 2014 and 2013, respectively. |
Potomac Electric Power Co [Member] | |
Pension and Other Postretirement Benefits | (8) PENSION AND OTHER POSTRETIREMENT BENEFITS Pepco accounts for its participation in PHI’s single-employer plans, the PHI Retirement Plan and its other postretirement benefits plan, the Pepco Holdings, Inc. Welfare Plan for Retirees (the OPEB Plan), as participation in multiemployer plans. For 2015, 2014 and 2013, Pepco was responsible for $30 million, $22 million and $34 million, respectively, of the pension and other postretirement net periodic benefit cost incurred by PHI. For the years ended December 31, 2015, 2014 and 2013, Pepco made no discretionary tax-deductible contributions to the PHI Retirement Plan. Pepco made contributions of $2 million, $1 million and $6 million, respectively, to the OPEB Plan for the years ended December 31, 2015, 2014 and 2013. At December 31, 2015 and 2014, Pepco’s Prepaid pension expense of $291 million and $316 million, respectively, and Other postretirement benefit obligations of $49 million and $57 million, respectively, effectively represent assets and benefit obligations resulting from Pepco’s participation in the Pepco Holdings benefit plans. Other Postretirement Benefit Plan Amendments During 2013, PHI approved two amendments to its other postretirement benefits plan. These amendments impacted the retiree medical plan and the retiree life insurance benefits, and became effective on January 1, 2014. As a result of the amendments, which were cumulatively significant, PHI remeasured its projected benefit obligation for other postretirement benefits as of July 1, 2013. The remeasurement resulted in a $7 million reduction in Pepco’s net periodic benefit cost for other postretirement benefits in 2014, when compared to 2013. Approximately 40% of net periodic other postretirement benefit costs were capitalized in 2014. |
Delmarva Power & Light Co/De [Member] | |
Pension and Other Postretirement Benefits | (9) PENSION AND OTHER POSTRETIREMENT BENEFITS DPL accounts for its participation in PHI’s single-employer plans, the PHI Retirement Plan and its other postretirement benefits plan, the Pepco Holdings, Inc. Welfare Plan for Retirees (the OPEB Plan), as participation in multiemployer plans. For 2015, 2014 and 2013, DPL was responsible for $15 million, $7 million and $18 million, respectively, of the pension and other postretirement net periodic benefit cost incurred by PHI. DPL made a discretionary tax-deductible contribution to the PHI Retirement Plan of zero, zero and $10 million for the years ended December 31, 2015, 2014 and 2013, respectively. In addition, DPL made contributions of zero, zero and $3 million, respectively, to the OPEB Plan for the years ended December 31, 2015, 2014 and 2013. At December 31, 2015 and 2014, DPL’s Prepaid pension expense of $205 million and $220 million, respectively, and Other postretirement benefit obligations of $19 million and $21 million, respectively, effectively represent assets and benefit obligations resulting from DPL’s participation in the PHI benefit plans. Other Postretirement Benefit Plan Amendments During 2013, PHI approved two amendments to its other postretirement benefits plan. These amendments impacted the retiree medical plan and the retiree life insurance benefits, and became effective on January 1, 2014. As a result of the amendments, which were cumulatively significant, PHI remeasured its projected benefit obligation for other postretirement benefits as of July 1, 2013. The remeasurement resulted in a $4 million reduction in DPL’s net periodic benefit cost for other postretirement benefits in 2014, when compared to 2013. |
Atlantic City Electric Co [Member] | |
Pension and Other Postretirement Benefits | (8) PENSION AND OTHER POSTRETIREMENT BENEFITS ACE accounts for its participation in PHI’s single-employer plans, the PHI Retirement Plan and its other postretirement benefits plan, the Pepco Holdings, Inc. Welfare Plan for Retirees (the OPEB Plan), as participation in multiemployer plans. For 2015, 2014 and 2013, ACE was responsible for $15 million, $13 million and $17 million, respectively, of the pension and other postretirement net periodic benefit cost incurred by PHI. ACE made discretionary tax-deductible contributions of zero, zero and $30 million to the PHI Retirement Plan for the years ended December 31, 2015, 2014 and 2013, respectively. In addition, ACE made contributions of $3 million, $3 million and $6 million to the OPEB Plan for the years ended December 31, 2015, 2014 and 2013, respectively. At December 31, 2015 and 2014, ACE’s Prepaid pension expense of $83 million and $96 million, and Other postretirement benefit obligations of $33 million and $36 million, respectively, effectively represent assets and benefit obligations resulting from ACE’s participation in these PHI benefit plans. Other Postretirement Benefit Plan Amendments During 2013, PHI approved two amendments to its other postretirement benefits plan. These amendments impacted the retiree medical plan and the retiree life insurance benefits, and became effective on January 1, 2014. As a result of the amendments, which were cumulatively significant, PHI remeasured its projected benefit obligation for other postretirement benefits as of July 1, 2013. The remeasurement resulted in a $3 million reduction in ACE’s net periodic benefit cost for other postretirement benefits in 2014, when compared to 2013. Approximately 45% of net periodic other postretirement benefit costs were capitalized in 2014. |
Debt
Debt | 12 Months Ended |
Dec. 31, 2015 | |
Debt | (10) DEBT Long-Term Debt The components of long-term debt are shown in the table below: At December 31, Interest Rate Maturity 2015 2014 (millions of dollars) First Mortgage Bonds Pepco: 3.05% 2022 $ 200 $ 200 6.20% (a)(b) 2022 110 110 3.60% 2024 400 400 5.75% (c)(d) 2034 100 100 5.40% (c)(d) 2035 175 175 6.50% (a)(c) 2037 500 500 7.90% 2038 250 250 4.15% 2043 450 250 4.95% 2043 150 150 ACE: 7.68% (e) 2015 - 2016 2 17 7.75% 2018 250 250 6.80% (d)(f) 2021 39 39 4.35% 2021 200 200 3.375% 2024 150 150 3.50% 2025 150 — 4.875% (a)(f) 2029 23 23 5.80% (d)(g) 2034 120 120 5.80% (d)(g) 2036 105 105 DPL: 5.22% (h) 2016 100 100 3.50% 2023 500 500 4.00% 2042 250 250 4.15% 2045 200 — Total First Mortgage Bonds 4,424 3,889 Unsecured Tax-Exempt Bonds DPL: 5.40% 2031 78 78 Total Unsecured Tax-Exempt Bonds 78 78 NOTE: Schedule is continued on next page. At December 31, Interest Rate Maturity 2015 2014 (millions of dollars) Medium-Term Notes (unsecured) DPL: 7.56% - 7.58% 2017 $ 14 $ 14 6.81% 2018 4 4 7.61% 2019 12 12 7.72% 2027 10 10 Total Medium-Term Notes (unsecured) 40 40 Notes (secured) Pepco Energy Services: 6.70% - 7.46% 2015-2018 3 4 Notes (unsecured) PHI: 2.70% 2015 — 250 5.90% 2016 190 190 6.125% 2017 81 81 7.45% 2032 185 185 DPL: 5.00% 2015 — 100 Total Notes (unsecured) 456 806 Total Long-Term Debt 5,001 4,817 Net unamortized discount (2 ) (10 ) Unamortized debt issuance costs (49 ) (44 ) Current portion of long-term debt (294 ) (366 ) Total Net Long-Term Debt $ 4,656 $ 4,397 (a) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for the issuer’s obligations under the corresponding series of issuer notes or tax-exempt bonds, at such time as the issuer does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds), except that the issuer may not permit such release of collateral unless the issuer substitutes comparable obligations for such collateral. (b) Represents a series of Collateral First Mortgage Bonds securing a series of senior notes issued by Pepco, which in turn secures a series of tax-exempt bonds issued for the benefit of Pepco. (c) Represents a series of Collateral First Mortgage Bonds (as defined herein) securing a series of senior notes issued by Pepco. (d) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for the issuer’s obligations under the corresponding series of issuer notes (as defined herein) or tax-exempt bonds, at such time as the issuer does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds). (e) Represents a series of Collateral First Mortgage Bonds securing a series of medium-term notes issued by ACE. (f) Represents a series of Collateral First Mortgage Bonds securing a series of tax-exempt bonds issued for the benefit of ACE. (g) Represents a series of Collateral First Mortgage Bonds securing a series of senior notes issued by ACE. (h) Represents a series of Collateral First Mortgage Bonds securing a series of debt securities issued by DPL. The outstanding first mortgage bonds issued by each of Pepco, DPL and ACE are issued under a mortgage and deed of trust and are secured by a first lien on substantially all of the issuing company’s property, plant and equipment, except for certain property excluded from the lien of the respective mortgage. PHI’s long-term debt is subject to certain covenants. As of December 31, 2015, PHI and its subsidiaries were in compliance with all such covenants. The table above does not separately identify $885 million, $100 million and $227 million in aggregate principal amount of senior notes, medium term notes and other debt securities (issuer notes) issued by each of Pepco, DPL and ACE, respectively, and $110 million and $62 million in aggregate principal amount of tax-exempt bonds issued for the benefit of Pepco and ACE, respectively. These issuer notes are secured by a like amount of first mortgage bonds (Collateral First Mortgage Bonds) of each respective issuer. In addition, these tax-exempt bonds are secured by a like amount of Collateral First Mortgage Bonds issued by the utility subsidiary for whose benefit the tax-exempt bonds were issued. The principal terms of each such series of issuer notes, or the issuer’s obligations in respect of each such series of tax-exempt bonds, are identical to the same terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest made on a series of such issuer notes, or the satisfaction of the issuer’s obligations in respect of a series of such tax-exempt bonds, satisfy the corresponding obligations on the related series of Collateral First Mortgage Bonds. For these reasons, each such series of Collateral First Mortgage Bonds and the corresponding issuer notes and/or tax-exempt bonds together effectively represent a single financial obligation and are not identified in the table above separately. Bond Issuances During 2015, Pepco issued $200 million of 4.15% first mortgage bonds due March 15, 2043, with a 3.9% yield to maturity. Net proceeds from the issuance of the bonds, which included a premium of $8 million, were used by Pepco to repay outstanding commercial paper and for general corporate purposes. During 2015, DPL issued $200 million of 4.15% first mortgage bonds due May 15, 2045. Net proceeds from the issuance of the bonds were used by DPL to repay outstanding commercial paper and for general corporate purposes. During 2015, ACE issued $150 million of 3.50% first mortgage bonds due December 1, 2025 in a private placement. The net proceeds from the issuance of the bonds were used by ACE to repay outstanding commercial paper and for general corporate purposes. Note Retirements During 2015, ACE retired, at maturity, $15 million of its secured medium-term notes series C. The medium-term notes were secured by a like principal amount of its 7.68% first mortgage bonds due August 24, 2015, which under the mortgage and deed of trust were deemed to be satisfied when the medium-term notes were repaid. During 2015, DPL retired, at maturity, $100 million of its 5.00% unsecured notes due June 1, 2015. During 2015, PHI retired, at maturity, $250 million of its 2.70% unsecured notes due October 1, 2015. Transition Bonds Issued by ACE Funding The components of transition bonds are shown in the table below: At December 31, Interest Rate Maturity 2015 2014 (millions of dollars) 4.91% 2017 $ — $ 17 5.05% 2020 39 51 5.55% 2023 132 147 Total Transition Bonds 171 215 Unamortized debt issuance costs (1 ) (1 ) Current portion of long-term debt (46 ) (44 ) Total Net Long-Term Transition Bonds $ 124 $ 170 For a description of the Transition Bonds, see Note (17), “Variable Interest Entities – ACE Funding.” Maturities of PHI’s Long-term Debt and Transition Bonds Maturities of PHI’s long-term debt and Transition Bonds outstanding at December 31, 2015 are $340 million in 2016, $131 million in 2017, $285 million in 2018, $30 million in 2019, $20 million in 2020 and $4,366 million thereafter. Long-Term Project Funding As of December 31, 2015 and 2014, Pepco Energy Services had total outstanding long-term project funding (including current maturities) of $5 million and $10 million, respectively, related to energy savings contracts performed by Pepco Energy Services. The aggregate amounts of maturities for the project funding debt outstanding at December 31, 2015 are $1 million in each of the years 2016 and 2017, zero in 2018, $1 million in 2019, $1 million in 2020, and $1 million thereafter. Short-Term Debt PHI and its regulated utility subsidiaries have traditionally used a number of sources to fulfill short-term funding needs, such as commercial paper, short-term notes, and bank lines of credit. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to temporarily fund long-term capital requirements. The components of PHI’s short-term debt at December 31, 2015 and 2014 are as follows: 2015 2014 (millions of dollars) Commercial paper $ 658 $ 624 Variable rate demand bonds 105 105 Term loan 300 — Total $ 1,063 $ 729 Commercial Paper PHI, Pepco, DPL and ACE maintain ongoing commercial paper programs to address short-term liquidity needs. As of December 31, 2015, the maximum capacity available under these programs was $875 million, $500 million, $500 million and $350 million, respectively, subject to available borrowing capacity under the credit facility. PHI, Pepco, DPL and ACE had $484 million, $64 million, $105 million and $5 million, respectively, of commercial paper outstanding at December 31, 2015. The weighted average interest rate for commercial paper issued by PHI, Pepco, DPL and ACE during 2015 was 0.80%, 0.44%, 0.47% and 0.46%, respectively. The weighted average maturity of all commercial paper issued by PHI, Pepco, DPL and ACE during 2015 was ten, four, four and six days, respectively. PHI, Pepco, DPL and ACE had $287 million, $104 million, $106 million and $127 million, respectively, of commercial paper outstanding at December 31, 2014. The weighted average interest rate for commercial paper issued by PHI, Pepco, DPL and ACE during 2014 was 0.57%, 0.28%, 0.26% and 0.27%, respectively. The weighted average maturity of all commercial paper issued by PHI, Pepco, DPL and ACE during 2014 was six, six, five and five days, respectively. Variable Rate Demand Bonds PHI’s utility subsidiary DPL has outstanding obligations in respect of Variable Rate Demand Bonds (VRDB). VRDBs are subject to repayment on the demand of the holders and, for this reason, are accounted for as short-term debt in accordance with GAAP. However, bonds submitted for purchase are remarketed by a remarketing agent on a best efforts basis. PHI expects that any bonds submitted for purchase will be remarketed successfully due to the creditworthiness of the issuer and, as applicable, the credit support, and because the remarketing resets the interest rate to the then-current market rate. The bonds may be converted to a fixed-rate, fixed-term option to establish a maturity which corresponds to the date of final maturity of the bonds. On this basis, PHI views VRDBs as a source of long-term financing. As of December 31, 2015, $105 million of VRDBs issued on behalf of DPL were outstanding (of which $72 million were secured by Collateral First Mortgage Bonds issued by DPL). During 2014, ACE retired, at maturity, its last remaining VRDBs in the amount of $18 million. The VRDBs outstanding at December 31, 2015 mature as follows: 2017 ($26 million), 2024 ($33 million), 2028 ($16 million), and 2029 ($30 million). The weighted average interest rate for VRDBs outstanding on December 31, 2015 was 0.13% during 2015 and 0.19% during 2014. PHI Term Loan Agreements On January 13, 2016, PHI entered into a $500 million term loan agreement, pursuant to which PHI borrowed $500 million at a rate of interest equal to the prevailing Eurodollar rate, which is determined by reference to the London Interbank Offered Rate with respect to the relevant interest period, all as defined in the loan agreement, plus a margin of 0.90%. PHI used the net proceeds of the loan under the loan agreement to repay its outstanding commercial paper, and for general corporate purposes. All indebtedness incurred under the loan agreement is unsecured, and the aggregate principal amount of all loans, together with any accrued but unpaid interest due under the loan agreement, must be repaid in full on or before July 13, 2016. Pursuant to the term loan agreement, PHI may consummate the Merger and the subsequent conversion of PHI from a Delaware corporation to a Delaware limited liability company, provided that the Merger and subsequent conversion are consummated on or before October 29, 2015. PHI requested and obtained the consent of the lenders under the term loan to allow for completion of the Merger by June 30, 2016. On July 30, 2015, PHI entered into a $300 million term loan agreement, pursuant to which PHI borrowed $300 million at a rate of interest equal to the prevailing Eurodollar rate, which is determined by reference to the LIBOR with respect to the relevant interest period, all as defined in the loan agreement, plus a margin of 0.95%. PHI used the net proceeds of the loan under the loan agreement to repay a portion of its outstanding commercial paper, and for general corporate purposes. All indebtedness incurred under the loan agreement is unsecured, and the aggregate principal amount of all loans, together with any accrued but unpaid interest due under the loan agreement, must be repaid in full on or before July 28, 2016. Pursuant to the term loan agreement, PHI may consummate the Merger and the subsequent conversion of PHI from a Delaware corporation to a Delaware limited liability company, provided that the Merger and subsequent conversion are consummated on or before October 29, 2015. PHI requested and obtained the consent of the lenders under the term loan to allow for completion of the Merger by June 30, 2016. Credit Facility PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. On August 1, 2013, as permitted under the existing terms of the credit agreement, a request by PHI, Pepco, DPL and ACE to extend the credit facility termination date to August 1, 2018 was approved. All of the terms and conditions as well as pricing remained the same. The aggregate borrowing limit under the amended and restated credit facility is $1.5 billion, all or any portion of which may be used to obtain loans and up to $500 million of which may be used to obtain letters of credit. The facility also includes a swingline loan sub-facility, pursuant to which each company may make same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt. The credit sublimit is $750 million for PHI and $250 million for each of Pepco, DPL and ACE. The sublimits may be increased or decreased by the individual borrower during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million and the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the sublimit reallocations may not exceed eight per year during the term of the facility. The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and the one month London Interbank Offered Rate (LIBOR) plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower. In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified financial and other covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) with certain exceptions, a restriction on sales or other dispositions of assets, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. The credit agreement contains certain covenants and other customary agreements and requirements that, if not complied with, could result in an event of default and the acceleration of repayment obligations of one or more of the borrowers thereunder. Each of the borrowers was in compliance with all covenants under this facility at December 31, 2015. The absence of a material adverse change in PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers. As of December 31, 2015 and December 31, 2014, the amount of cash plus unused borrowing capacity under the credit facility available to meet the future liquidity needs of PHI and its utility subsidiaries on a consolidated basis totaled $851 million and $875 million, respectively. PHI’s utility subsidiaries had combined cash and unused borrowing capacity under the credit facility of $576 million and $413 million at December 31, 2015 and December 31, 2014, respectively. Credit Facility Amendment During 2014, PHI, Pepco, DPL and ACE entered into an amendment of and consent with respect to the credit agreement (the Consent). PHI was required to obtain the consent of certain of the lenders under the credit facility in order to permit the consummation of the Merger. Pursuant to the Consent, certain of the lenders consented to the consummation of the Merger and the subsequent conversion of PHI from a Delaware corporation to a Delaware limited liability company, provided that the Merger and subsequent conversion are consummated on or before October 29, 2015. In addition, the Consent amends the definition of “Change in Control” in the credit agreement to mean, following consummation of the Merger, an event or series of events by which Exelon no longer owns, directly or indirectly, 100% of the outstanding shares of voting stock of Pepco Holdings. PHI requested and obtained an extension of the Consent to allow for completion of the Merger by June 30, 2016. Other Financing Activities Sale of Receivables During 2015, Pepco, as seller, entered into a purchase agreement with a buyer to sell receivables from an energy savings project over a period of time pursuant to a task order. The purchase price to be received by Pepco is $5 million. Pursuant to the purchase agreement, following acceptance of the energy savings project by the buyer, the buyer is entitled to receive the contract payments under the task order payable by the customer over approximately 15 years. The energy savings project will be performed by Pepco Energy Services and is expected to be completed by the end of 2017. During 2014, Pepco, as seller, entered into a purchase agreement with a buyer to sell receivables from an energy savings project pursuant to a task order entered into under a General Services Administration area-wide agreement. The purchase price received by Pepco was $12 million, which was included in the Current portion of long-term debt and project funding at December 31, 2014. The energy savings project was performed by Pepco Energy Services and was completed in 2014. Pursuant to the purchase agreement, following acceptance of the energy savings project by the buyer, the buyer was entitled to receive the contract payments under the task order payable by the buyer over approximately 9 years. The energy savings project was accepted during the first quarter of 2015 and the amount was removed from the Current portion of long-term debt and project funding. During 2013, Pepco Energy Services, as seller, entered into a purchase agreement with a buyer to sell receivables from an energy savings project over a period of time pursuant to a task order. The purchase price received by Pepco Energy Services was $7 million, which was included in the Current portion of long-term debt and project funding at December 31, 2014. Pursuant to the purchase agreement, following acceptance of the energy savings project by the buyer, the buyer is entitled to receive the contract payments under the task order payable by the customer over approximately 23 years. The energy savings project was accepted during the first quarter of 2015 and the amount was removed from the Current portion of long-term debt and project funding. ACE Term Loan Agreement On May 10, 2013, ACE entered into a $100 million term loan agreement, pursuant to which ACE borrowed $100 million at a rate of interest equal to the prevailing Eurodollar rate, which was determined by reference to the LIBOR with respect to the relevant interest period, all as defined in the loan agreement, plus a margin of 0.75%. On August 21, 2014, ACE repaid the term loan in full. |
Potomac Electric Power Co [Member] | |
Debt | (9) DEBT Long-Term Debt The components of long-term debt are shown in the table below: Type of Debt Interest Rate Maturity 2015 2014 (millions of dollars) First Mortgage Bonds 3.05 % 2022 $ 200 $ 200 6.20 %(a)(b) 2022 110 110 3.60 % 2024 400 400 5.75 %(c)(d) 2034 100 100 5.40 %(c)(d) 2035 175 175 6.50 %(a)(c) 2037 500 500 7.90 % 2038 250 250 4.15 % 2043 450 250 4.95 % 2043 150 150 Total long-term debt 2,335 2,135 Net unamortized discount (3 ) (11 ) Unamortized debt issuance costs (31 ) (28 ) Total net long-term debt $ 2,301 $ 2,096 (a) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for Pepco’s obligations under the corresponding series of senior notes or tax-exempt bonds, at such time as Pepco does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds), except that Pepco may not permit such release of collateral unless Pepco substitutes comparable obligations for such collateral. (b) Represents a series of Collateral First Mortgage Bonds securing a series of senior notes issued by Pepco, which in turn secures a series of tax-exempt bonds issued for the benefit of Pepco. (c) Represents a series of Collateral First Mortgage Bonds (as defined herein) securing a series of senior notes issued by Pepco. (d) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for Pepco’s obligations under the corresponding series of senior notes or tax-exempt bonds, at such time as Pepco does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds). The outstanding first mortgage bonds are issued under a mortgage and deed of trust and are secured by a first lien on substantially all of Pepco’s property, plant and equipment, except for certain property excluded from the lien of the mortgage. Maturities of Pepco’s long-term debt outstanding at December 31, 2015, are zero in 2016 through 2020, and $2,335 million, thereafter. Pepco’s long-term debt is subject to certain covenants. As of December 31, 2015, Pepco is in compliance with all such covenants. The table above does not separately identify $885 million in aggregate principal amount of senior notes issued by Pepco and $110 million in aggregate principal amount of tax-exempt bonds issued for the benefit of Pepco. These senior notes are secured by a like amount of first mortgage bonds (Collateral First Mortgage Bonds) of Pepco. In addition, these tax-exempt bonds are secured by a like amount of Collateral First Mortgage Bonds issued by Pepco. The principal terms of each such series of senior notes, or Pepco’s obligations in respect of each such series of tax-exempt bonds, are identical to the same terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest made on a series of such senior notes, or the satisfaction of Pepco’s obligations in respect of a series of such tax-exempt bonds, satisfy the corresponding obligations on the related series of Collateral First Mortgage Bonds. For these reasons, each such series of Collateral First Mortgage Bonds and the corresponding senior notes and/or tax-exempt bonds together effectively represent a single financial obligation and are not identified in the table above separately. Bond Issuances During 2015, Pepco issued $200 million of 4.15% first mortgage bonds due March 15, 2043, with a 3.9% yield to maturity. Net proceeds from the issuance of the bonds, which included a premium of $8 million, were used by Pepco to repay outstanding commercial paper and for general corporate purposes. Short-Term Debt Pepco has traditionally used a number of sources to fulfill short-term funding needs, such as commercial paper, short-term notes, and bank lines of credit. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to temporarily fund long-term capital requirements. Pepco’s short-term debt at December 31, 2015 and 2014 consisted of the following: 2015 2014 (millions of dollars) Commercial paper $ 64 $ 104 Commercial Paper Pepco maintains an ongoing commercial paper program to address its short-term liquidity needs. As of December 31, 2015, the maximum capacity available under the program was $500 million, subject to available borrowing capacity under the credit facility. Pepco had $64 million and $104 million of commercial paper outstanding at December 31, 2015 and 2014, respectively. The weighted average interest rates for commercial paper issued by Pepco during 2015 and 2014 were 0.44% and 0.28%, respectively. The weighted average maturity of all commercial paper issued by Pepco during 2015 and 2014 was four days and six days, respectively. Credit Facility PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. On August 1, 2013, as permitted under the existing terms of the credit agreement, a request by PHI, Pepco, DPL and ACE to extend the credit facility termination date to August 1, 2018 was approved. All of the terms and conditions as well as pricing remained the same. The aggregate borrowing limit under the amended and restated credit facility is $1.5 billion, all or any portion of which may be used to obtain loans and up to $500 million of which may be used to obtain letters of credit. The facility also includes a swingline loan sub-facility, pursuant to which each company may make same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt. The credit sublimit is $750 million for PHI and $250 million for each of Pepco, DPL and ACE. The sublimits may be increased or decreased by the individual borrower during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million and the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the sublimit reallocations may not exceed eight per year during the term of the facility. The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and the one month London Interbank Offered Rate plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower. In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified financial and other covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) with certain exceptions, a restriction on sales or other dispositions of assets, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. The credit agreement contains certain covenants and other customary agreements and requirements that, if not complied with, could result in an event of default and the acceleration of repayment obligations of one or more of the borrowers thereunder. Each of the borrowers was in compliance with all covenants under this facility at December 31, 2015. The absence of a material adverse change in PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers. As of December 31, 2015 and 2014, the amount of cash plus borrowing capacity under the credit facility available to meet the liquidity needs of PHI’s utility subsidiaries in the aggregate was $576 million and $413 million, respectively. Pepco’s borrowing capacity under the credit facility at any given time depends on the amount of the subsidiary borrowing capacity being utilized by DPL and ACE and the portion of the total capacity being used by PHI. Credit Facility Amendment During 2014, PHI, Pepco, DPL and ACE entered into an amendment of and consent with respect to the credit agreement (the Consent). PHI was required to obtain the consent of certain of the lenders under the credit facility in order to permit the consummation of the Merger. Pursuant to the Consent, certain of the lenders consented to the consummation of the Merger and the subsequent conversion of PHI from a Delaware corporation to a Delaware limited liability company, provided that the Merger and subsequent conversion are consummated on or before October 29, 2015. In addition, the Consent amends the definition of “Change in Control” in the credit agreement to mean, following consummation of the Merger, an event or series of events by which Exelon no longer owns, directly or indirectly, 100% of the outstanding shares of voting stock of Pepco Holdings. PHI requested and obtained an extension of the Consent to allow for completion of the Merger by June 30, 2016. Other Financing Activities Sale of Receivables During 2015, Pepco, as seller, entered into a purchase agreement with a buyer to sell receivables from an energy savings project over a period of time pursuant to a task order. The purchase price to be received by Pepco is $5 million. Pursuant to the purchase agreement, following acceptance of the energy savings project by the buyer, the buyer is entitled to receive the contract payments under the task order payable by the customer over approximately 15 years. The energy savings project will be performed by Pepco Energy Services, Inc. and its subsidiaries (Pepco Energy Services) and is expected to be completed by the end of 2017. During 2014, Pepco, as seller, entered into a purchase agreement with a buyer to sell receivables from an energy savings project pursuant to a task order entered into under a General Services Administration area-wide agreement. The purchase price received by Pepco was $12 million, which was included in the Current portion of long-term debt and project funding at December 31, 2014. The energy savings project was performed by Pepco Energy Services and was completed in 2014. Pursuant to the purchase agreement, following acceptance of the energy savings project by the buyer, the buyer was entitled to receive the contract payments under the task order payable by the buyer over approximately 9 years. The energy savings project was accepted during the first quarter of 2015 and the amount was removed from the Current portion of long-term debt and project funding. |
Delmarva Power & Light Co/De [Member] | |
Debt | (10) DEBT Long-Term Debt The components of long-term debt are shown in the table below: Type of Debt Interest Rate Maturity 2015 2014 (millions of dollars) First Mortgage Bonds 5.22%(a) 2016 $ 100 $ 100 3.50% 2023 500 500 4.00% 2042 250 250 4.15% 2045 200 — 1,050 850 Unsecured Tax-Exempt Bonds 5.40% 2031 78 78 78 78 Medium-Term Notes (unsecured) 7.56%-7.58% 2017 14 14 6.81% 2018 4 4 7.61% 2019 12 12 7.72% 2027 10 10 40 40 Notes (unsecured) 5.00% 2015 — 100 — 100 Total long-term debt 1,168 1,068 Net unamortized premium 2 3 Unamortized debt issuance costs (9 ) (8 ) Current portion of long-term debt (100 ) (100 ) Total net long-term debt $ 1,061 $ 963 (a) Represents a series of Collateral First Mortgage Bonds securing a series of debt securities issued by DPL. The outstanding first mortgage bonds issued by DPL are issued under a Mortgage and Deed of Trust and are secured by a first lien on substantially all of DPL’s property, plant and equipment, except for certain property excluded from the lien of the mortgage. Maturities of DPL’s long-term debt outstanding at December 31, 2015 are $100 million in 2016, $14 million in 2017, $4 million in 2018, $12 million in 2019, zero in 2020 and $1,038 million thereafter. DPL’s long-term debt is subject to certain covenants. As of December 31, 2015, DPL is in compliance with all such covenants. The table above does not separately identify $100 million in aggregate principal amount of debt securities issued by DPL. These debt securities are secured by a like amount of first mortgage bonds (Collateral First Mortgage Bonds) of DPL. The principal terms of each such series of debt securities are identical to the same terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest made on a series of such debt securities, satisfy the corresponding obligations on the related series of Collateral First Mortgage Bonds. For these reasons, each such series of Collateral First Mortgage Bonds and the corresponding debt securities together effectively represent a single financial obligation and are not identified in the table above separately. Bond Issuance During 2015, DPL issued $200 million of 4.15% first mortgage bonds due May 15, 2045. Net proceeds from the issuance of the bonds were used by DPL to repay outstanding commercial paper and for general corporate purposes. Note Retirements During 2015, DPL retired, at maturity, $100 million of its 5.00% unsecured notes due June 1, 2015. Short-Term Debt DPL has traditionally used a number of sources to fulfill short-term funding needs, such as commercial paper, short-term notes, and bank lines of credit. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to temporarily fund long-term capital requirements. The components of DPL’s short-term debt at December 31, 2015 and 2014 are as follows: 2015 2014 (millions of dollars) Commercial paper $ 105 $ 106 Variable rate demand bonds 105 105 Total $ 210 $ 211 Commercial Paper DPL maintains an ongoing commercial paper program to address its short-term liquidity needs. As of December 31, 2015, the maximum capacity available under the program was $500 million, subject to available borrowing capacity under the credit facility. DPL had $105 million and $106 million of commercial paper outstanding at December 31, 2015 and 2014, respectively. The weighted average interest rates for commercial paper issued by DPL during 2015 and 2014 were 0.47% and 0.26%, respectively. The weighted average maturity of all commercial paper issued by DPL during 2015 and 2014 was four days and five days, respectively. Variable Rate Demand Bonds Variable Rate Demand Bonds (VRDBs) are subject to repayment on the demand of the holders and, for this reason, are accounted for as short-term debt in accordance with accounting principles generally accepted in the United States of America. However, bonds submitted for purchase are remarketed by a remarketing agent on a best efforts basis. DPL expects that any bonds submitted for purchase will continue to be remarketed successfully due to the creditworthiness of the company and because the remarketing agent resets the interest rate to the then-current market rate. The bonds may be converted to a fixed rate, fixed term option to establish a maturity which corresponds to the date of final maturity of the bonds. On this basis, DPL views VRDBs as a source of long-term financing. The VRDBs outstanding in 2015 mature as follows: 2017 ($26 million), 2024 ($33 million), 2028 ($16 million), and 2029 ($30 million). The weighted average interest rate for VRDBs was 0.13% during 2015 and 0.19% during 2014. As of December 31, 2015, $105 million in VRDBs issued on behalf of DPL were outstanding (of which $72 million were secured by Collateral First Mortgage Bonds issued by DPL). Credit Facility PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. On August 1, 2013, as permitted under the existing terms of the credit agreement, a request by PHI, Pepco, DPL and ACE to extend the credit facility termination date to August 1, 2018 was approved. All of the terms and conditions as well as pricing remained the same. The aggregate borrowing limit under the amended and restated credit facility is $1.5 billion, all or any portion of which may be used to obtain loans and up to $500 million of which may be used to obtain letters of credit. The facility also includes a swingline loan sub-facility, pursuant to which each company may make same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt. The credit sublimit is $750 million for PHI and $250 million for each of Pepco, DPL and ACE. The sublimits may be increased or decreased by the individual borrower during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion, and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the sublimit reallocations may not exceed eight per year during the term of the facility. The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and the one month London Interbank Offered Rate plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower. In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified financial and other covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) with certain exceptions, a restriction on sales or other dispositions of assets, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. The credit agreement contains certain covenants and other customary agreements and requirements that, if not complied with, could result in an event of default and the acceleration of repayment obligations of one or more of the borrowers thereunder. Each of the borrowers was in compliance with all covenants under this facility at December 31, 2015. The absence of a material adverse change in PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers. As of December 31, 2015 and 2014, the amount of cash plus borrowing capacity under the credit facility available to meet the liquidity needs of PHI’s utility subsidiaries in the aggregate was $576 million and $413 million, respectively. DPL’s borrowing capacity under the credit facility at any given time depends on the amount of the subsidiary borrowing capacity being utilized by Pepco and ACE and the portion of the total capacity being used by PHI. Credit Facility Amendment During 2014, PHI, Pepco, DPL and ACE entered into an amendment of and consent with respect to the credit agreement (the Consent). PHI was required to obtain the consent of certain of the lenders under the credit facility in order to permit the consummation of the Merger. Pursuant to the Consent, certain of the lenders consented to the consummation of the Merger and the subsequent conversion of PHI from a Delaware corporation to a Delaware limited liability company, provided that the Merger and subsequent conversion are consummated on or before October 29, 2015. In addition, the Consent amends the definition of “Change in Control” in the credit agreement to mean, following consummation of the Merger, an event or series of events by which Exelon no longer owns, directly or indirectly, 100% of the outstanding shares of voting stock of Pepco Holdings. PHI requested and obtained an extension of the Consent to allow for completion of the Merger by June 30, 2016. |
Atlantic City Electric Co [Member] | |
Debt | (9) DEBT Long-Term Debt The components of long-term debt are shown in the table below: Type of Debt Interest Rate Maturity 2015 2014 (millions of dollars) First Mortgage Bonds 7.68 % (a) 2015-2016 $ 2 $ 17 7.75 % 2018 250 250 6.80 % (b)(c) 2021 39 39 4.35 % 2021 200 200 3.375 % 2024 150 150 3.50 % 2025 150 — 4.875 %(c)(d) 2029 23 23 5.80 % (b)(e) 2034 120 120 5.80 % (b)(e) 2036 105 105 Total long-term debt 1,039 904 Net unamortized discount (1 ) (1 ) Unamortized debt issuance costs (6 ) (6 ) Current portion of long-term debt (2 ) (15 ) Total net long-term debt $ 1,030 $ 882 (a) Represents a series of Collateral First Mortgage Bonds (as defined herein) securing a series of medium-term notes issued by ACE. (b) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for ACE’s obligations under the corresponding series of issuer notes (as defined herein) or tax-exempt bonds, at such time as ACE does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds). (c) Represents a series of Collateral First Mortgage Bonds securing a series of tax-exempt bonds issued for the benefit of ACE. (d) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for ACE’s obligations under the corresponding series of issuer notes or tax-exempt bonds, at such time as ACE does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds), except that ACE may not permit such release of collateral unless ACE substitutes comparable obligations for such collateral. (e) Represents a series of Collateral First Mortgage Bonds securing a series of senior notes issued by ACE. The outstanding first mortgage bonds issued by ACE are issued under a mortgage and deed of trust and are secured by a first lien on substantially all of ACE’s property, plant and equipment, except for certain property excluded from the lien of the mortgage. Maturities of ACE’s long-term debt outstanding at December 31, 2015 are $2 million in 2016, zero in 2017, $250 million in 2018, zero in 2019 and 2020, and $787 million thereafter. ACE’s long-term debt is subject to certain covenants. As of December 31, 2015, ACE was in compliance with all such covenants. The table above does not separately identify $227 million in aggregate principal amount of senior notes and medium term notes (issuer notes) issued by ACE and $62 million in aggregate principal amount of tax-exempt bonds issued for the benefit of ACE. These issuer notes and tax-exempt bonds are secured by a like amount of first mortgage bonds (Collateral First Mortgage Bonds) of ACE. The principal terms of each such series of issuer notes, or ACE’s obligations in respect of each such series of tax-exempt bonds, are identical to the same terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest made on a series of such issuer notes, or the satisfaction of ACE obligations in respect of a series of such tax-exempt bonds, satisfy the corresponding obligations on the related series of Collateral First Mortgage Bonds. For these reasons, each such series of Collateral First Mortgage Bonds and the corresponding issuer notes or tax-exempt bonds together effectively represent a single financial obligation and are not identified in the table above separately. Bond Issuance During 2015, ACE issued $150 million of 3.50% first mortgage bonds due December 1, 2025 in a private placement. The net proceeds from the issuance of the bonds were used by ACE to repay outstanding commercial paper and for general corporate purposes. Bond Retirement During 2015, ACE retired, at maturity, $15 million of its secured medium-term notes series C. The medium-term notes were secured by a like principal amount of its 7.68% first mortgage bonds due August 24, 2015, which under the mortgage and deed of trust were deemed to be satisfied when the medium-term notes were repaid. Transition Bonds Issued by ACE Funding The components of transition bonds are shown in the table below: Type of Debt Interest Rate Maturity 2015 2014 (millions of dollars) Transition Bonds 4.91 % 2017 $ — $ 17 5.05 % 2020 39 51 5.55 % 2023 132 147 171 215 Unamortized debt issuance costs (1 ) (1 ) Current portion of long-term debt (46 ) (44 ) Total net long-term Transition Bonds $ 124 $ 170 For a description of the Transition Bonds, see Note (16), “Variable Interest Entities – ACE Funding.” Maturities of ACE’s Transition Bonds outstanding at December 31, 2015 are $46 million in 2016, $35 million in 2017, $31 million in 2018, $18 million in 2019, $20 million in 2020 and $21 million thereafter. Short-Term Debt ACE has traditionally used a number of sources to fulfill short-term funding needs, such as commercial paper, short-term notes, and bank lines of credit. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to temporarily fund long-term capital requirements. The components of ACE’s short-term debt at December 31, 2015 and 2014 are as follows: 2015 2014 (millions of dollars) Commercial paper $ 5 $ 127 Commercial Paper ACE maintains an ongoing commercial paper program to address its short-term liquidity needs. As of December 31, 2015, the maximum capacity available under the program was $350 million, subject to available borrowing capacity under the credit facility. ACE had $5 million and $127 million of commercial paper outstanding at December 31, 2015 and 2014, respectively. The weighted average interest rates for commercial paper issued by ACE during 2015 and 2014 were 0.46% and 0.27%, respectively. The weighted average maturity of all commercial paper issued by ACE during 2015 and 2014 was six days and five days, respectively. Variable Rate Demand Bonds During 2014, ACE retired, at maturity, its last remaining Variable Rate Demand Bonds (VRDBs) in the amount of $18 million. The weighted average interest rate for VRDBs was 0.05% during 2014. Credit Facility PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. On August 1, 2013, as permitted under the existing terms of the credit agreement, a request by PHI, Pepco, DPL and ACE to extend the credit facility termination date to August 1, 2018 was approved. All of the terms and conditions as well as pricing remained the same. The aggregate borrowing limit under the amended and restated credit facility is $1.5 billion, all or any portion of which may be used to obtain loans and up to $500 million of which may be used to obtain letters of credit. The facility also includes a swingline loan sub-facility, pursuant to which each company may make same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt. The credit sublimit is $750 million for PHI and $250 million for each of Pepco, DPL and ACE. The sublimits may be increased or decreased by the individual borrower during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion, and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the sublimit reallocations may not exceed eight per year during the term of the facility. The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and the one month London Interbank Offered Rate plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower. In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified financial and other covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) with certain exceptions, a restriction on sales or other dispositions of assets, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. The credit agreement contains certain covenants and other customary agreements and requirements that, if not complied with, could result in an event of default and the acceleration of repayment obligations of one or more of the borrowers thereunder. Each of the borrowers was in compliance with all covenants under this facility at December 31, 2015. The absence of a material adverse change in PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers. As of December 31, 2015 and 2014, the amount of cash plus borrowing capacity under the credit facility available to meet the liquidity needs of PHI’s utility subsidiaries in the aggregate was $576 million and $413 million, respectively. ACE’s borrowing capacity under the credit facility at any given time depends on the amount of the subsidiary borrowing capacity being utilized by Pepco and DPL and the portion of the total capacity being used by PHI. Credit Facility Amendment During 2014, PHI, Pepco, DPL and ACE entered into an amendment of and consent with respect to the credit agreement (the Consent). PHI was required to obtain the consent of certain of the lenders under the credit facility in order to permit the consummation of the Merger. Pursuant to the Consent, certain of the lenders consented to the consummation of the Merger and the subsequent conversion of PHI from a Delaware corporation to a Delaware limited liability company, provided that the Merger and subsequent conversion are consummated on or before October 29, 2015. In addition, the Consent amends the definition of “Change in Control” in the credit agreement to mean, following consummation of the Merger, an event or series of events by which Exelon no longer owns, directly or indirectly, 100% of the outstanding shares of voting stock of Pepco Holdings. PHI requested and obtained an extension of the Consent to allow for completion of the Merger by June 30, 2016. Term Loan Agreement On May 10, 2013, ACE entered into a $100 million term loan agreement, pursuant to which ACE borrowed $100 million at a rate of interest equal to the prevailing Eurodollar rate, which was determined by reference to the London Interbank Offered Rate (LIBOR) with respect to the relevant interest period, all as defined in the loan agreement, plus a margin of 0.75%. On August 21, 2014, ACE repaid the term loan in full. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2015 | |
Income Taxes | (11) INCOME TAXES PHI and the majority of its subsidiaries file a consolidated federal income tax return. Federal income taxes are allocated among PHI and the subsidiaries included in its consolidated group pursuant to a written tax sharing agreement that was approved by the SEC in 2002 in connection with the establishment of PHI as a public utility holding company. Under this tax sharing agreement, PHI’s consolidated federal income tax liability is allocated based upon PHI’s and its subsidiaries’ separate taxable income or loss. The provision for consolidated income taxes, reconciliation of consolidated income tax expense, and components of consolidated deferred tax liabilities (assets) are shown below. Provision for Consolidated Income Taxes – Continuing Operations For the Year Ended December 31, 2015 2014 2013 (millions of dollars) Current Tax (Benefit) Expense Federal $ (3 ) $ (137 ) $ (128 ) State and local 12 (26 ) (9 ) Total Current Tax Expense (Benefit) 9 (163 ) (137 ) Deferred Tax Expense (Benefit) Federal 92 261 393 State and local 30 41 65 Investment tax credit amortization (2 ) (1 ) (2 ) Total Deferred Tax Expense 120 301 456 Total Consolidated Income Tax Expense Related to Continuing Operations $ 129 $ 138 $ 319 Reconciliation of Consolidated Income Tax Expense – Continuing Operations For the Year Ended December 31, 2015 2014 2013 (millions of dollars) Income tax at Federal statutory rate $ 156 35.0 % $ 133 35.0 % $ 150 35.0 % Increases (decreases) resulting from: State income taxes, net of federal effect 27 6.0 % 23 6.1 % 27 6.3 % Asset removal costs (14 ) (3.1 )% (12 ) (3.2 )% (14 ) (3.3 )% Change in estimates and interest related to uncertain and effectively settled tax positions (46 ) (10.3 )% — — 56 13.1 % Deferred tax basis adjustments 7 1.6 % — — — — Establishment of valuation allowances related to deferred tax assets — — — — 101 23.5 % Merger related costs 4 0.9 % 7 1.8 % — — Other, net (5 ) (1.2 )% (13 ) (3.4 )% (1 ) (0.2 )% Consolidated Income Tax Expense Related to Continuing Operations $ 129 28.9 % $ 138 36.3 % $ 319 74.4 % Global Tax Settlement On November 18, 2015, PHI entered into a settlement with the IRS and the DOJ (the Global Tax Settlement) to provide for the resolution of the tax treatment of its previously held cross-border energy lease investments involving public utility assets located outside of the United States structured as sale-in, lease-out, or SILO, transactions. The Global Tax Settlement followed the acceptance by PHI on October 29, 2015 of IRS revenue agent reports covering adjustments incorporated in the terms of the Global Tax Settlement, as well as adjustments for all other tax matters in dispute with the IRS. Also, on November 18, 2015, the DOJ accepted PHI’s offer letter for the settlement of litigation related to the SILO transactions discussed further in Note (16), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease Investments.” The Global Tax Settlement and the revenue agent reports, together, effectively close all years open to examination of federal income tax liabilities for PHI through 2011, and all matters associated with the cross-border energy lease investments through 2013. The Global Tax Settlement, which resolves tax matters related to the cross-border energy lease investments and avoids the costs associated with continued litigation, provides that all depreciation and interest deductions in excess of rental income related to the cross-border energy lease investments were disallowed. The Global Tax Settlement also required PHI to recognize original issue discount income for tax purposes associated with the recharacterization of each of the leases as a loan transaction. Pursuant to the Global Tax Settlement, interest will be assessed with respect to tax underpayments in the relevant years; however, no penalties were assessed against PHI. The Global Tax Settlement provides for the same treatment of the cross-border energy lease investments for the tax years 2012 and 2013 as described above. The last of PHI’s cross-border energy lease investments was terminated in 2013. As a result of the Global Tax Settlement, PHI and the DOJ filed stipulations of dismissal regarding the litigation in the U.S. Court of Federal Claims. The Court dismissed the complaint on November 20, 2015. As a result of the Global Tax Settlement, PHI recorded in the fourth quarter of 2015 a tax benefit of $56 million, including $47 million associated with continuing operations and $9 million associated with discontinued operations. The $47 million benefit associated with continuing operations is included above in Change in estimates and interest related to uncertain and effectively settled tax positions. Included in the tax benefit of $47 million associated with continuing operations was a $21 million after-tax interest benefit representing the anticipated reduction in previously recorded interest expense that was allocated to PHI’s continuing operations associated with PHI’s uncertain tax positions. The remaining tax benefit recorded of $26 million primarily represents uncertain tax positions associated with PHI’s continuing operations that were settled in favor of PHI in the Global Tax Settlement. Also during the fourth quarter of 2015, PHI completed its annual reconciliation of its deferred income tax accounts and corrected prior period errors by recording an after-tax charge of $7 million which is included above in Deferred tax basis adjustments. Management has determined that these errors, individually or in the aggregate, were not material to the current or prior periods. Other Tax Matters During 2015 and 2014, PHI recorded tax benefits of $6 million and $5 million, respectively, related to certain energy efficiency tax deductions associated with Pepco Energy Services’ energy savings performance contracting services. Theses tax benefits are included above in Other, net. In connection with the proposed Merger (as further described in Note (1), “Organization”), PHI incurred certain merger-related costs in 2015 and 2014 which are not tax-deductible. During 2013, PHI recorded a $56 million charge for a change in estimates and interest related to uncertain and effectively settled tax positions, primarily representing the anticipated additional interest expense on estimated federal and state income tax obligations that was allocated to PHI’s continuing operations resulting from a change in assessment of tax benefits associated with the former cross-border energy lease investments of PCI in the first quarter of 2013. Also, in 2013, PHI established valuation allowances of $101 million related to deferred tax assets. Between 1990 and 1999, PCI, through various subsidiaries, entered into certain transactions involving investments in aircraft and aircraft equipment, railcars and other assets. In connection with these transactions, PCI recorded deferred tax assets in prior years of $101 million in the aggregate. Following events that took place during the first quarter of 2013, which included (i) court decisions in favor of the IRS with respect to other taxpayers’ cross-border lease and other structured transactions (as discussed in Note (20), “Discontinued Operations – Cross-Border Energy Lease Investments”), (ii) the change in PHI’s tax position with respect to the tax benefits associated with its cross-border energy leases, and (iii) PHI’s decision in March 2013 to begin to pursue the early termination of its remaining cross-border energy lease investments (which represented a substantial portion of the remaining assets within PCI) without the intent to reinvest these proceeds in income-producing assets, management evaluated the likelihood that PCI would be able to realize the $101 million of deferred tax assets in the future. Based on this evaluation, PCI established valuation allowances against these deferred tax assets totaling $101 million in the first quarter of 2013. Further, during the fourth quarter of 2013, in light of additional court decisions in favor of the IRS involving other taxpayers, and after consideration of all relevant factors, management determined that it would abandon the further pursuit of these deferred tax assets, and these assets totaling $101 million were charged off against the previously established valuation allowances. Components of Consolidated Deferred Tax Liabilities (Assets) At December 31, 2015 2014 (millions of dollars) Deferred Tax Liabilities (Assets) Depreciation and other basis differences related to plant and equipment $ 3,273 $ 2,962 Deferred electric service and electric restructuring liabilities 43 67 Federal and state net operating losses (446 ) (400 ) Valuation allowances on state net operating losses 63 61 Pension and other postretirement benefits 92 116 Deferred taxes on amounts to be collected through future rates 86 94 Other 267 325 Total Deferred Tax Liabilities, net 3,378 3,225 Deferred tax assets included in Other Assets 15 17 Total Consolidated Deferred Tax Liabilities, net $ 3,393 $ 3,242 The net deferred tax liability represents the tax effect, at presently enacted tax rates, of temporary differences between the financial statement basis and tax basis of assets and liabilities. The portion of the net deferred tax liability applicable to PHI’s utility operations, which has not been reflected in current service rates, represents income taxes recoverable through future rates, net, and is recorded as a Regulatory asset on the balance sheet. Federal and state net operating losses generally expire over 20 years from 2029 to 2034. The Tax Reform Act of 1986 repealed the investment tax credit for property placed in service after December 31, 1985, except for certain transition property. Investment tax credits previously earned on Pepco’s, DPL’s and ACE’s property continue to be amortized to income over the useful lives of the related property. Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits 2015 2014 2013 (millions of dollars) Balance as of January 1, $ 850 $ 831 $ 200 Tax positions related to current year: Additions — 4 3 Reductions — (2 ) — Tax positions related to prior years: Additions 13 27 646 (b) Reductions (201 )(a) (10 ) (12 ) Settlements (628 )(a) — (6 ) Balance as of December 31, $ 34 $ 850 $ 831 (a) Reductions and settlements in 2015 resulted from the Global Tax Settlement. Settlements represent unrecognized tax benefits that were satisfied with cash or use of net operating losses and tax credits. The majority of the settlements were associated with the treatment of the former cross-border energy lease investments of PCI. (b) These additions of unrecognized tax benefits in 2013 primarily relate to the former cross-border energy lease investments of PCI. Unrecognized Benefits That, If Recognized, Would Affect the Effective Tax Rate Unrecognized tax benefits are related to tax positions that have been taken or are expected to be taken in tax returns that are not recognized in the financial statements because management has either measured the tax benefit at an amount less than the benefit claimed or expected to be claimed, or has concluded that it is not more likely than not that the tax position will be ultimately sustained. For the majority of these tax positions, the ultimate deductibility is highly certain, but there is uncertainty about the timing of such deductibility. Unrecognized tax benefits at December 31, 2015 included $22 million that, if recognized, would lower the effective tax rate. Interest and Penalties PHI recognizes interest and penalties relating to its uncertain tax positions as an element of income tax expense. For the years ended December 31, 2015, 2014 and 2013, PHI recognized $35 million of pre-tax interest income ($21 million after-tax), less than $1 million of pre-tax interest expense, and $125 million of pre-tax interest expense ($75 million after-tax), respectively, as a component of income tax expense related to continuing and discontinued operations. As of December 31, 2015, 2014 and 2013, PHI had accrued interest payable of $2 million, accrued interest receivable of $2 million and accrued interest receivable of $2 million, respectively, related to effectively settled and uncertain tax positions. Possible Changes to Unrecognized Tax Benefits It is reasonably possible that the amount of unrecognized tax benefits with respect to PHI’s uncertain tax positions will significantly increase or decrease within the next 12 months. At this time, it is estimated that there will be a $6 million to $10 million decrease in unrecognized tax benefits within the next 12 months. Tax Years Open to Examination As a result of the Global Tax Settlement, PHI’s federal income tax liabilities for PHI and Pepco legacy companies for all years through 2011, and for all matters associated with the cross-border energy lease investments for all years through 2013, have been determined by the IRS, subject to adjustment to the extent of any net operating loss or other loss or credit carrybacks from subsequent years. The open tax years for the significant states where PHI files state income tax returns (District of Columbia, Maryland, Delaware, New Jersey, Pennsylvania and Virginia) are the same as for the Federal returns. Changes to the District of Columbia Tax Law On February 26, 2015, the District of Columbia Fiscal Year 2015 Budget Support Act of 2014 became law, effective January 1, 2015. The law revised the apportionment methodology for corporate tax and included a phase-down of the corporate tax rate from 9.975% to 8.25% by fiscal year 2019. The change in law required PHI and Pepco to remeasure their net deferred tax liabilities in the first and fourth quarters of 2015. This remeasurement resulted in Pepco reducing its deferred tax liabilities by $23 million in the first quarter of 2015 to reflect the initial reduction in the tax rate from 9.975% to 9.4% on January 1, 2015 and $2 million in the fourth quarter of 2015 to reflect the subsequent reduction in the tax rate from 9.4% to 9.2% on January 1, 2016. These reductions to the deferred tax liabilities were offset by corresponding decreases to Pepco’s regulatory assets. Further reductions to the corporate tax rate in future years will depend upon the achievement of future revenue projections for the District of Columbia. Final IRS Regulations on Repair of Tangible Property In August 2011, the IRS issued Revenue Procedure 2011-43 providing a safe harbor method of tax accounting for repair costs associated with electric transmission and distribution property. In September 2012, with the filing of its 2011 tax return, PHI adopted the safe harbor for the 2011 tax year. In September 2013, the IRS published final regulations regarding the tax treatment of costs incurred to acquire, produce or improve tangible property. In February 2014, the IRS issued revenue procedures that describe how taxpayers should implement the final regulations. The final repair regulations and the related revenue procedures did not modify the guidance set forth in Revenue Procedure 2011-43 that the Unit of Property for electric transmission and distribution network assets is determined by the taxpayer’s particular facts and circumstances. The final regulations did not have a material impact on PHI’s consolidated financial statements. Other Taxes Other taxes for continuing operations are shown below. The annual amounts include $421 million, $407 million and $422 million for the years ended December 31, 2015, 2014 and 2013, respectively, related to Power Delivery, which are recoverable through rates. 2015 2014 2013 (millions of dollars) Gross Receipts/Delivery $ 124 $ 123 $ 133 Property 92 84 77 County Fuel and Energy 143 143 153 Environmental, Use and Other 68 63 65 Total $ 427 $ 413 $ 428 |
Potomac Electric Power Co [Member] | |
Income Taxes | (10) INCOME TAXES Pepco, as a direct subsidiary of PHI, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to Pepco pursuant to a written tax sharing agreement that was approved by the Securities and Exchange Commission in connection with the establishment of PHI as a holding company. Under this tax sharing agreement, PHI’s consolidated federal income tax liability is allocated based upon PHI’s and its subsidiaries’ separate taxable income or loss. The provision for income taxes, reconciliation of income tax expense, and components of deferred income tax liabilities (assets) are shown below. Provision for Income Taxes For the Year Ended December 31, 2015 2014 2013 (millions of dollars) Current Tax Benefit Federal $ (57 ) $ (79 ) $ (39 ) State and local 6 (3 ) (1 ) Total Current Tax Benefit (51 ) (82 ) (40 ) Deferred Tax Expense (Benefit) Federal 125 150 96 State and local 24 24 24 Investment tax credit amortization — — (1 ) Total Deferred Tax Expense 149 174 119 Total Income Tax Expense $ 98 $ 92 $ 79 Reconciliation of Income Tax Expense For the Year Ended December 31, 2015 2014 2013 (millions of dollars) Income tax at Federal statutory rate $ 100 35.0 % $ 92 35.0 % $ 80 35.0 % Increases (decreases) resulting from: State income taxes, net of federal effect 15 5.3 % 15 5.7 % 13 5.7 % Asset removal costs (14 ) (4.9 )% (12 ) (4.6 )% (14 ) (6.1 )% Change in estimates and interest related to uncertain and effectively settled tax positions (6 ) (2.1 )% (1 ) (0.4 )% (3 ) (1.3 )% Deferred tax basis adjustments 6 2.1 % — — — — Other, net (3 ) (1.0 )% (2 ) (0.7 )% 3 1.2 % Income Tax Expense $ 98 34.4 % $ 92 35.0 % $ 79 34.5 % Global Tax Settlement On November 18, 2015, PHI entered into a settlement with the Internal Revenue Service (IRS) and the Department of Justice (DOJ) (the Global Tax Settlement) to provide for the resolution of the tax treatment of its previously held cross-border energy lease investments involving public utility assets located outside of the United States structured as sale-in, lease-out, or SILO, transactions. The Global Tax Settlement followed the acceptance by PHI on October 29, 2015 of IRS revenue agent reports covering adjustments incorporated in the terms of the Global Tax Settlement, as well as adjustments for all other tax matters in dispute with the IRS. The Global Tax Settlement and the revenue agent reports, together, effectively close all years open to examination of federal income tax liabilities for PHI and Pepco through 2011, and all matters associated with the cross-border energy lease investments through 2013. As a result of the Global Tax Settlement, Pepco recorded in the fourth quarter of 2015 a tax benefit of $9 million, which is included above in Change in estimates and interest related to uncertain and effectively settled tax positions. Included in the tax benefit of $9 million was a $3 million after-tax interest benefit associated with Pepco’s uncertain tax positions. The interest benefit represented Pepco’s allocated share of an overall net interest benefit for PHI’s consolidated group of $21 million resulting from the Global Tax Settlement assuming Pepco was a separate taxpayer. The remaining tax benefit recorded of $6 million primarily represents uncertain tax positions associated with Pepco’s operations that were settled in favor of Pepco in the Global Tax Settlement. Also in the fourth quarter of 2015, Pepco recorded a charge of $3 million for an uncertain tax position not related to the Global Tax Settlement, which was also included above in Change in estimates and interest related to uncertain and effectively settled tax positions. Also during the fourth quarter of 2015, Pepco completed its annual reconciliation of its deferred income tax accounts and corrected prior period errors by recording an after-tax charge of $6 million which is included above in Deferred tax basis adjustments. Management has determined that these errors, individually or in the aggregate were not material to the current or prior periods. Other Tax Matter On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States Components of Deferred Income Tax Liabilities (Assets) At December 31, 2015 2014 (millions of dollars) Deferred Tax Liabilities (Assets) Depreciation and other basis differences related to plant and equipment $ 1,541 $ 1,423 Pension and other postretirement benefits 95 103 Deferred taxes on amounts to be collected through future rates 55 59 Federal and state net operating losses (141 ) (186 ) Other 171 180 Total Deferred Tax Liabilities, net $ 1,721 $ 1,579 The net deferred tax liability represents the tax effect, at presently enacted tax rates, of temporary differences between the financial statement basis and tax basis of assets and liabilities. The portion of the net deferred tax liability applicable to Pepco’s operations, which has not been reflected in current service rates, represents income taxes recoverable through future rates, net, and is recorded as a regulatory asset on the balance sheet. No valuation allowance for deferred tax assets was required or recorded at December 31, 2015 and 2014. Federal and state net operating losses generally expire over 20 years from 2029 to 2034. The Tax Reform Act of 1986 repealed the investment tax credit for property placed in service after December 31, 1985, except for certain transition property. Investment tax credits previously earned on Pepco’s property continue to be amortized to income over the useful lives of the related property. Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits 2015 2014 2013 (millions of dollars) Balance as of January 1 $ 97 $ 101 $ 91 Tax positions related to current year: Additions — 1 1 Reductions — (2 ) — Tax positions related to prior years: Additions 10 1 12 Reductions (55 )(a) (4 ) (3 ) Settlements (40 )(a) — — Balance as of December 31 $ 12 $ 97 $ 101 (a) Reductions and settlements in 2015 resulted from the Global Tax Settlement. Settlements represent unrecognized tax benefits that were satisfied with cash or use of net operating losses and tax credits. Unrecognized Benefits That, If Recognized, Would Affect the Effective Tax Rate Unrecognized tax benefits are related to tax positions that have been taken or are expected to be taken in tax returns that are not recognized in the financial statements because management has either measured the tax benefit at an amount less than the benefit claimed, or expected to be claimed, or has concluded that it is not more likely than not that the tax position will be ultimately sustained. For the majority of these tax positions, the ultimate deductibility is highly certain, but there is uncertainty about the timing of such deductibility. At December 31, 2015, Pepco had $8 million of unrecognized tax benefits that, if recognized, would lower the effective tax rate. Interest and Penalties Pepco recognizes interest and penalties relating to its uncertain tax positions as an element of income tax expense. For the years ended December 31, 2015, 2014 and 2013, Pepco recognized $5 million of pre-tax interest income ($3 million after-tax), $2 million of pre-tax interest income ($1 million after-tax), and $5 million of pre-tax interest income ($3 million after-tax), respectively, as a component of income tax expense. As of December 31, 2015, 2014 and 2013, Pepco had accrued interest receivable of zero, $9 million and $9 million, respectively, related to effectively settled and uncertain tax positions. Possible Changes to Unrecognized Tax Benefits It is reasonably possible that the amount of the unrecognized tax benefit with respect to some of Pepco’s uncertain tax positions will significantly increase or decrease within the next 12 months. At this time, it is estimated that there will be a $3 million to $5 million decrease in unrecognized tax benefits within the next 12 months. Tax Years Open to Examination Pepco, as a direct subsidiary of PHI, is included on PHI’s consolidated Federal income tax return. As a result of the Global Tax Settlement described above, Pepco’s federal income tax liabilities for all years through 2011 have been determined, subject to adjustment to the extent of any net operating loss or other loss or credit carrybacks from subsequent years. The open tax years for the significant states where Pepco files state income tax returns (District of Columbia and Maryland) are the same as for the Federal returns. As a result of the final determination of these years, Pepco has filed or intends to file amended state returns requesting refunds which are subject to review by the various states. Changes to the District of Columbia Tax Law On February 26, 2015, the District of Columbia Fiscal Year 2015 Budget Support Act of 2014 became law, effective January 1, 2015. The law revised the apportionment methodology for corporate tax and included a phase-down of the corporate tax rate from 9.975% to 8.25% by fiscal year 2019. The change in law required PHI and Pepco to remeasure their net deferred tax liabilities in the first and fourth quarters of 2015. This remeasurement resulted in Pepco reducing its deferred tax liabilities by $23 million in the first quarter of 2015 to reflect the initial reduction in the tax rate from 9.975% to 9.4% on January 1, 2015 and $2 million in the fourth quarter of 2015 to reflect the subsequent reduction in the tax rate from 9.4% to 9.2% on January 1, 2016. These reductions to the deferred tax liabilities were offset by corresponding decreases to Pepco’s regulatory assets. Further reductions to the corporate tax rate in future years will depend upon the achievement of future revenue projections for the District of Columbia. Final IRS Regulations on Repair of Tangible Property In August 2011, the IRS issued Revenue Procedure 2011-43 providing a safe harbor method of tax accounting for repair costs associated with electric transmission and distribution property. In September 2012, with the filing of its 2011 tax return, PHI adopted the safe harbor for the 2011 tax year. In September 2013, the IRS published final regulations regarding the tax treatment of costs incurred to acquire, produce or improve tangible property. In February 2014, the IRS issued revenue procedures that describe how taxpayers should implement the final regulations. The final repair regulations and the related revenue procedures did not modify the guidance set forth in Revenue Procedure 2011-43 that the Unit of Property for electric transmission and distribution network assets is determined by the taxpayer’s particular facts and circumstances. The final regulations did not have a material impact on Pepco’s financial statements. Other Taxes Taxes other than income taxes for each year are shown below. These amounts are recoverable through rates. 2015 2014 2013 (millions of dollars) Gross Receipts/Delivery $ 107 $ 107 $ 108 Property 55 51 45 County Fuel and Energy 143 143 153 Environmental, Use and Other 64 62 62 Total $ 369 $ 363 $ 368 |
Delmarva Power & Light Co/De [Member] | |
Income Taxes | (11) INCOME TAXES DPL, as an indirect subsidiary of PHI, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to DPL pursuant to a written tax sharing agreement that was approved by the Securities and Exchange Commission in connection with the establishment of PHI as a holding company. Under this tax sharing agreement, PHI’s consolidated federal income tax liability is allocated based upon PHI’s and its subsidiaries’ separate taxable income or loss. The provision for income taxes, reconciliation of income tax expense, and components of deferred income tax liabilities (assets) are shown below. Provision for Income Taxes For the Year Ended December 31, 2015 2014 2013 (millions of dollars) Current Tax (Benefit) Expense Federal $ (26 ) $ (45 ) $ (8 ) State and local 2 — — Total Current Tax Benefit (24 ) (45 ) (8 ) Deferred Tax Expense (Benefit) Federal 73 99 53 State and local 1 12 12 Investment tax credit amortization (1 ) (1 ) (1 ) Total Deferred Tax Expense 73 110 64 Total Income Tax Expense $ 49 $ 65 $ 56 Reconciliation of Income Tax Expense For the Year Ended December 31, 2015 2014 2013 (millions of dollars) Income tax at Federal statutory rate $ 44 35.0 % $ 59 35.0 % $ 51 35.0 % Increases (decreases) resulting from: State income taxes, net of federal effect 7 5.6 % 9 5.3 % 8 5.5 % Change in estimates and interest related to uncertain and effectively settled tax positions 3 2.4 % — — (1 ) (0.7 )% Other, net (5 ) (3.8 )% (3 ) (1.8 )% (2 ) (1.2 )% Income Tax Expense $ 49 39.2 % $ 65 38.5 % $ 56 38.6 % Global Tax Settlement On November 18, 2015, PHI entered into a settlement with the Internal Revenue Service (IRS) and the Department of Justice (DOJ) (the Global Tax Settlement) to provide for the resolution of the tax treatment of its previously held cross-border energy lease investments involving public utility assets located outside of the United States structured as sale-in, lease-out, or SILO, transactions. The Global Tax Settlement followed the acceptance by PHI on October 29, 2015 of IRS revenue agent reports covering adjustments incorporated in the terms of the Global Tax Settlement, as well as adjustments for all other tax matters in dispute with the IRS. The Global Tax Settlement and the revenue agent reports, together, effectively close all years open to examination of federal income tax liabilities for PHI and DPL through 2011, and all matters associated with the cross-border energy lease investments through 2013. As a result of the Global Tax Settlement, DPL recorded in the fourth quarter of 2015 tax expense of $3 million which is included above in Change in estimates and interest related to uncertain and effectively settled tax positions. The tax charge recorded of $3 million primarily represents uncertain tax positions that were settled in favor of the IRS in the Global Tax Settlement. Included in the tax expense of $3 million was an after-tax interest benefit of less than $1 million associated with DPL’s uncertain tax positions. The interest benefit represented DPL’s allocated share of an overall net interest benefit for PHI’s consolidated group of $21 million resulting from the Global Tax Settlement assuming DPL was a separate taxpayer. Other Tax Matter On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States Components of Deferred Income Tax Liabilities (Assets) As of December 31, 2015 2014 (millions of dollars) Deferred Tax Liabilities (Assets) Depreciation and other basis differences related to plant and equipment $ 899 $ 797 Deferred taxes on amounts to be collected through future rates 15 19 Federal and state net operating losses (122 ) (115 ) Pension and other postretirement benefits 75 80 Electric restructuring liabilities (4 ) (4 ) Other 78 101 Total Deferred Tax Liabilities, net $ 941 $ 878 The net deferred tax liability represents the tax effect, at presently enacted tax rates, of temporary differences between the financial statement basis and tax basis of assets and liabilities. The portion of the net deferred tax liability applicable to DPL’s operations, which has not been reflected in current service rates, represents income taxes recoverable through future rates, net, and is recorded as a regulatory asset on the balance sheet. No valuation allowance for deferred tax assets was required or recorded at December 31, 2015 and 2014. Federal and state net operating losses generally expire over 20 years from 2029 to 2034. The Tax Reform Act of 1986 repealed the investment tax credit for property placed in service after December 31, 1985, except for certain transition property. Investment tax credits previously earned on DPL’s property continue to be amortized to income over the useful lives of the related property. Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits 2015 2014 2013 (millions of dollars) Balance as of January 1 $ 22 $ 9 $ 9 Tax positions related to current year: Additions — 1 — Reductions — — — Tax positions related to prior years: Additions 3 13 — Reductions (13 )(a) (1 ) — Settlements (9 )(a) — — Balance as of December 31 $ 3 $ 22 $ 9 (a) Reductions and settlements in 2015 resulted from the Global Tax Settlement. Settlements represent unrecognized tax benefits that were satisfied with cash or use of net operating losses and tax credits. Unrecognized Benefits That, If Recognized, Would Affect the Effective Tax Rate Unrecognized tax benefits are related to tax positions that have been taken or are expected to be taken in tax returns that are not recognized in the financial statements because management has either measured the tax benefit at an amount less than the benefit claimed, or expected to be claimed, or has concluded that it is not more likely than not that the tax position will be ultimately sustained. For the majority of these tax positions, the ultimate deductibility is highly certain, but there is uncertainty about the timing of such deductibility. At December 31, 2015, DPL had $3 million of unrecognized tax benefits that, if recognized, would lower the effective tax rate. Interest and Penalties DPL recognizes interest and penalties relating to its uncertain tax positions as an element of income tax expense. For each of the years ended December 31, 2015, 2014 and 2013, DPL recognized less than $1 million of pre-tax interest income as a component of income tax expense. As of December 31, 2015, 2014 and 2013, DPL had accrued interest receivable of zero, $2 million and $2 million, respectively, related to effectively settled and uncertain tax positions. Possible Changes to Unrecognized Tax Benefits It is reasonably possible that the amount of the unrecognized tax benefit with respect to some of DPL’s uncertain tax positions will significantly increase or decrease within the next 12 months. At this time, it is estimated that there will be no decrease in unrecognized tax benefits within the next 12 months. Tax Years Open to Examination DPL, as an indirect subsidiary of PHI, is included on PHI’s consolidated Federal tax return. As a result of the Global Tax Settlement described above, DPL’s federal income tax liabilities for all years through 2011 have been determined, subject to adjustment to the extent of any net operating loss or other loss or credit carrybacks from subsequent years. The open tax years for the significant states where DPL files state income tax returns (Maryland and Delaware) are the same as for the Federal returns. Final IRS Regulations on Repair of Tangible Property In August 2011, the IRS issued Revenue Procedure 2011-43 providing a safe harbor method of tax accounting for repair costs associated with electric transmission and distribution property. In September 2012, with the filing of its 2011 tax return, PHI adopted the safe harbor for the 2011 tax year. In September 2013, the IRS published final regulations regarding the tax treatment of costs incurred to acquire, produce or improve tangible property. In February 2014, the IRS issued revenue procedures that describe how taxpayers should implement the final regulations. The final repair regulations and the related revenue procedures did not modify the guidance set forth in Revenue Procedure 2011-43 that the Unit of Property for electric transmission and distribution network assets is determined by the taxpayer’s particular facts and circumstances. The final regulations did not have a material impact on DPL’s financial statements. Other Taxes Taxes other than income taxes for each year are shown below. These amounts are recoverable through rates. 2015 2014 2013 (millions of dollars) Gross Receipts/Delivery $ 17 $ 16 $ 15 Property 28 24 24 Environmental, Use and Other 2 2 1 Total $ 47 $ 42 $ 40 |
Atlantic City Electric Co [Member] | |
Income Taxes | (10) INCOME TAXES ACE, as an indirect subsidiary of PHI, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to ACE pursuant to a written tax sharing agreement that was approved by the Securities and Exchange Commission in connection with the establishment of PHI as a holding company. Under this tax sharing agreement, PHI’s consolidated federal income tax liability is allocated based upon PHI’s and its subsidiaries’ separate taxable income or loss. The provision for consolidated income taxes, reconciliation of consolidated income tax expense, and components of consolidated deferred income tax liabilities (assets) are shown below. Provision for Consolidated Income Taxes For the Year Ended December 31, 2015 2014 2013 (millions of dollars) Current Tax (Benefit) Expense Federal $ (2 ) $ (7 ) $ (23 ) State and local 3 (2 ) (10 ) Total Current Tax Benefit 1 (9 ) (33 ) Deferred Tax Expense (Benefit) Federal 25 30 28 State and local 5 7 25 Investment tax credit amortization — — (1 ) Total Deferred Tax Expense 30 37 52 Total Consolidated Income Tax Expense $ 31 $ 28 $ 19 Reconciliation of Consolidated Income Tax Expense For the Year Ended December 31, 2015 2014 2013 (millions of dollars) Income tax at Federal statutory rate $ 24 35.0 % $ 26 35.0 % $ 24 35.0 % Increases (decreases) resulting from: State income taxes, net of federal effect 4 5.8 % 4 5.5 % 5 7.2 % Change in estimates and interest related to uncertain and effectively settled tax positions 3 4.3 % (1 ) (1.4 )% (9 ) (13.0 )% Deferred tax basis adjustments 2 2.9 % — — (2 ) (2.9 )% Investment tax credit amortization — — — — (1 ) (1.4 )% Other, net (2 ) (3.1 )% (1 ) (0.7 )% 2 2.6 % Consolidated Income Tax Expense $ 31 44.9 % $ 28 38.4 % $ 19 27.5 % Global Tax Settlement On November 18, 2015, PHI entered into a settlement with the IRS and the Department of Justice (DOJ) (the Global Tax Settlement) to provide for the resolution of the tax treatment of its previously held cross-border energy lease investments involving public utility assets located outside of the United States structured as sale-in, lease-out, or SILO, transactions. The Global Tax Settlement followed the acceptance by PHI on October 29, 2015 of IRS revenue agent reports covering adjustments incorporated in the terms of the Global Tax Settlement, as well as adjustments for all other tax matters in dispute with the IRS. The Global Tax Settlement and the revenue agent reports, together, effectively close all years open to examination of federal income tax liabilities for PHI and ACE through 2011, and all matters associated with the cross-border energy lease investments through 2013. As a result of the Global Tax Settlement, ACE recorded in the fourth quarter of 2015 tax expense of $3 million which is included above in Change in estimates and interest related to uncertain and effectively settled tax positions. The tax charge recorded of $3 million primarily represents uncertain tax positions that were settled in favor of the IRS in the Global Tax Settlement. Included in the tax expense of $3 million was after-tax interest expense of less than $1 million associated with ACE’s uncertain tax positions. The interest expense represented ACE’s allocated share of an overall net interest benefit for PHI’s consolidated group of $21 million resulting from the Global Tax Settlement assuming ACE was a separate taxpayer. Also during the fourth quarter of 2015, ACE completed its annual reconciliation of its deferred income tax accounts and corrected prior period errors by recording an after-tax charge of $2 million which is included above in Deferred tax basis adjustments. Management has determined that these errors, individually or in the aggregate, were not material to the current or prior periods. Other Tax Matter On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States Components of Consolidated Deferred Income Tax Liabilities (Assets) As of December 31, 2015 2014 (millions of dollars) Deferred Tax Liabilities (Assets) Depreciation and other basis differences related to plant and equipment $ 773 $ 691 Deferred taxes on amounts to be collected through future rates 17 16 Payment for termination of purchased power contracts with NUGs 34 38 Deferred electric service and electric restructuring liabilities 47 71 Pension and other postretirement benefits 20 25 Federal and state net operating losses (9 ) (26 ) Other 6 40 Total Consolidated Deferred Tax Liabilities, net $ 888 $ 855 The net deferred tax liability represents the tax effect, at presently enacted tax rates, of temporary differences between the financial statement basis and tax basis of assets and liabilities. The portion of the net deferred tax liability applicable to ACE’s operations, which has not been reflected in current service rates, represents income taxes recoverable through future rates, net, and is recorded as a regulatory asset on the balance sheet. No valuation allowance for deferred tax assets was required or recorded at December 31, 2015 and 2014. Federal and State net operating losses generally expire over 20 years from 2029 to 2032. The Tax Reform Act of 1986 repealed the investment tax credit for property placed in service after December 31, 1985, except for certain transition property. Investment tax credits previously earned on ACE’s property continue to be amortized to income over the useful lives of the related property. Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits 2015 2014 2013 (millions of dollars) Balance as of January 1 $ 13 $ 9 $ 17 Tax positions related to current year: Additions — 1 2 Reductions — — — Tax positions related to prior years: Additions — 5 1 Reductions (10 )(a) (2 ) (5 ) Settlements (3 )(a) — (6 ) Balance as of December 31 $ — $ 13 $ 9 (a) Reductions and settlements in 2015 resulted from the Global Tax Settlement. Settlements represent unrecognized tax benefits that were satisfied with cash or use of net operating losses and tax credits. Unrecognized Benefits That, If Recognized, Would Affect the Effective Tax Rate Unrecognized tax benefits are related to tax positions that have been taken or are expected to be taken in tax returns that are not recognized in the financial statements because management has either measured the tax benefit at an amount less than the benefit claimed, or expected to be claimed, or has concluded that it is not more likely than not that the tax position will be ultimately sustained. For the majority of these tax positions, the ultimate deductibility is highly certain, but there is uncertainty about the timing of such deductibility. At December 31, 2015, ACE had no unrecognized tax benefits that, if recognized, would lower the effective tax rate. Interest and Penalties ACE recognizes interest and penalties relating to its uncertain tax positions as an element of income tax expense. For the years ended December 31, 2015, 2014 and 2013, ACE recognized less than $1 million of pre-tax interest income (less than $1 million after-tax), $1 million of pre-tax interest income (less than $1 million after-tax), and $12 million of pre-tax interest income ($7 million after-tax), respectively, as a component of income tax expense. As of December 31, 2015, 2014 and 2013, ACE had accrued interest receivable of zero, $14 million and $14 million, respectively, related to effectively settled and uncertain tax positions. Possible Changes to Unrecognized Tax Benefits It is reasonably possible that the amount of the unrecognized tax benefit with respect to some of ACE’s uncertain tax positions will significantly increase or decrease within the next 12 months. At this time, it is estimated that there will no decrease in unrecognized tax benefits within the next 12 months. Tax Years Open to Examination ACE, as an indirect subsidiary of PHI, is included on PHI’s consolidated Federal tax return. As a result of the Global Tax Settlement described above, ACE’s federal income tax liabilities for all years through 2011 have been determined, subject to adjustment to the extent of any net operating loss or other loss or credit carrybacks from subsequent years. The open tax years for the significant states where ACE files state income tax returns (New Jersey and Pennsylvania) are the same as for the Federal returns. Final IRS Regulations on Repair of Tangible Property In August 2011, the IRS issued Revenue Procedure 2011-43 providing a safe harbor method of tax accounting for repair costs associated with electric transmission and distribution property. In September 2012, with the filing of its 2011 tax return, PHI adopted the safe harbor for the 2011 tax year. In September 2013, the IRS published final regulations regarding the tax treatment of costs incurred to acquire, produce or improve tangible property. In February 2014, the IRS issued revenue procedures that describe how taxpayers should implement the final regulations. The final repair regulations and the related revenue procedures did not modify the guidance set forth in Revenue Procedure 2011-43 that the Unit of Property for electric transmission and distribution network assets is determined by the taxpayer’s particular facts and circumstances. The final regulations did not have a material impact on ACE’s consolidated financial statements. Other Taxes Taxes other than income taxes for each year are shown below. These amounts are recoverable through rates. 2015 2014 2013 (millions of dollars) Gross Receipts/Delivery $ — $ — $ 10 Property 4 3 3 Environmental, Use and Other 1 (1 ) 1 Total $ 5 $ 2 $ 14 |
Stock-Based Compensation, Divid
Stock-Based Compensation, Dividend Restrictions, and Calculations of Earnings Per Share of Common Stock | 12 Months Ended |
Dec. 31, 2015 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Stock-Based Compensation, Dividend Restrictions, and Calculations of Earnings Per Share of Common Stock | (12) STOCK-BASED COMPENSATION, DIVIDEND RESTRICTIONS, AND CALCULATIONS OF EARNINGS PER SHARE OF COMMON STOCK Stock-Based Compensation Pepco Holdings maintains the 2012 Long-Term Incentive Plan (2012 LTIP), the successor plan to the Long-Term Incentive Plan (LTIP), the objective of which is to increase shareholder value by providing long-term and equity incentives to reward officers, key employees and non-employee directors of Pepco Holdings and its subsidiaries and to increase the ownership of Pepco Holdings common stock by such individuals. Any officer, key employee or non-employee director of Pepco Holdings or its subsidiaries may be designated as a participant. Under these plans, awards to officers, key employees and non-employee directors may be in the form of restricted stock, restricted stock units, stock options, performance shares and/or units, stock appreciation rights, unrestricted stock and dividend equivalents. At inception, 10 million and 8 million shares of common stock were authorized for issuance under the LTIP and the 2012 LTIP, respectively. The LTIP expired in accordance with its terms in 2012 and no new awards may be granted thereunder. Total stock-based compensation expense recorded in the consolidated statements of income (loss) for the years ended December 31, 2015, 2014 and 2013 was $13 million, $18 million and $12 million, respectively, all of which was associated with restricted stock and restricted stock unit awards. No material amount of stock compensation expense was capitalized for the years ended December 31, 2015, 2014 and 2013. Restricted Stock and Restricted Stock Unit Awards Description of Awards A number of programs have been established under the LTIP and the 2012 LTIP involving the issuance of restricted stock and restricted stock unit awards, including awards of performance-based restricted stock and restricted stock units, and time-based restricted stock and restricted stock units. A summary of each of these programs is as follows: • Under the performance-based program, performance criteria are selected and measured over the specified performance period. Depending on the extent to which the performance criteria are satisfied, the participants are eligible to earn shares of common stock at the end of the performance period, ranging from 25% to 200% of the target award, and dividend equivalents accrued thereon. • Generally, time-based restricted stock and restricted stock unit award opportunities have a requisite service period of up to three years and, with respect to restricted stock awards, participants have the right to receive dividends on the shares during the vesting period. Under restricted stock unit awards, dividends are credited quarterly in the form of additional restricted stock units, which are paid when vested at the end of the service period. • PHI granted a total of 22,901 and 21,138 time-based restricted stock units in 2015 and 2014, respectively, to its non-employee directors under the 2012 LTIP. These time-based restricted stock units vest over a service period which ends upon the first to occur of (i) one year after the date of grant or (ii) the date of the next annual meeting of stockholders. These awards represent the equity portion of the annual retainer paid to non-employee directors for their service as a director of PHI. Activity for the year The 2015 activity for restricted stock, performance-based restricted stock, time-based restricted stock unit and performance-based restricted stock unit awards is summarized in the table below. For performance-based restricted stock and restricted stock unit awards, the table reflects awards projected, for purposes of computing the weighted average grant date fair value, to achieve 100% of targeted performance criteria for each outstanding award cycle. Number Weighted Balance as of January 1, 2015 Restricted stock 54,165 $ 26.80 Performance-based restricted stock 70,276 27.01 Time-based restricted stock units 468,958 19.61 Performance-based restricted stock units 827,981 17.73 Total 1,421,380 Granted during 2015 Performance-based restricted stock 48,347 26.10 Time-based restricted stock units 450,203 27.40 Performance-based restricted stock units 6,188 26.08 Total 504,738 Vested during 2015 Performance-based restricted stock (93,906 ) 26.78 Time-based restricted stock units (288,429 ) 20.61 Performance-based restricted stock units (424,705 ) 17.05 Total (807,040 ) Forfeited during 2015 Time-based restricted stock units (2,218 ) 27.00 Performance-based restricted stock units (826 ) 19.33 Total (3,044 ) Balance as of December 31, 2015 Restricted stock 54,165 26.80 Performance-based restricted stock 24,717 26.10 Time-based restricted stock units 628,514 24.71 Performance-based restricted stock units 408,638 18.56 Total 1,116,034 (a) The balance as of December 31, 2015 does not include 36,110 shares of restricted stock, 113,385 time-based restricted stock units and 104,628 performance-based restricted stock units that were vested for executives and 30,784 time-based restricted stock units that were vested for directors but had not yet settled. Grants included in the table above reflect 2015 grants of restricted stock, performance-based restricted stock, time-based restricted stock unit and performance-based restricted stock unit awards. PHI recognizes compensation expense related to restricted stock, performance-based restricted stock, time-based restricted stock unit and performance-based restricted stock unit awards based on the fair value of the awards at date of grant. The fair value is based on the market value of PHI common stock at the date the award opportunity is granted. The estimated fair value of the performance-based awards is also a function of PHI’s projected future performance relative to established performance criteria and the resulting payout of shares based on the achieved performance levels. PHI employed a Monte Carlo simulation to forecast PHI’s performance relative to the performance criteria and to estimate the potential payout of shares under the performance-based awards. The following table provides the weighted average grant date fair value per share of those awards granted during each of the years ended December 31, 2015, 2014 and 2013: 2015 2014 2013 Weighted average grant-date fair value of each restricted stock award granted during the year $ — $ 26.80 $ — Weighted average grant-date fair value of each performance-based restricted stock award granted during the year $ 26.10 $ 27.01 $ — Weighted average grant-date fair value of each time-based restricted stock unit award granted during the year $ 27.40 $ 19.77 $ 19.70 Weighted average grant-date fair value of each performance-based restricted stock unit award granted during the year $ 26.08 $ 18.53 $ 17.03 As of December 31, 2015, there was approximately $12 million of future compensation cost (net of estimated forfeitures) related to restricted stock unit awards granted under the LTIP and the 2012 LTIP that PHI expects to recognize over a weighted-average period of approximately two years. Stock Options Stock options to purchase shares of PHI’s common stock granted under the LTIP and the 2012 LTIP must have an exercise price at least equal to the fair market value of the underlying stock on the grant date. Stock options generally become exercisable on a specified vesting date or dates. All stock options must have an expiration date of no greater than ten years from the date of grant. No options have been granted under the LTIP or the 2012 LTIP since 2002. Directors’ Deferred Compensation Under the Pepco Holdings’ Executive and Director Deferred Compensation Plan, Pepco Holdings non-employee directors may elect to defer all or part of their cash retainer and meeting fees. Deferred retainer or meeting fees, at the election of the director, can be credited with interest at the prime rate or the return on selected investment funds or can be deemed invested in phantom shares of Pepco Holdings common stock on which dividend equivalent accruals are credited when dividends are paid on the common stock (or a combination of these options). All deferrals are settled in cash. The amount deferred by directors for the year ended December 31, 2015 was zero and was not material for each of the years ended December 31, 2014 and 2013. Compensation expense recognized in respect of dividends and the increase in fair value was not material for each of the years ended December 31, 2015 and 2013, and $1 million for the year ended December 31, 2014. The deferred compensation balances under this program were approximately $2 million at December 31, 2015 and 2014. A separate deferral option under the 2012 LTIP gives non-employee directors the right to elect to defer the receipt of common stock upon vesting of restricted stock unit awards. Dividend Restrictions PHI, on a stand-alone basis, generates no operating income of its own. Accordingly, its ability to pay dividends to its stockholders depends on dividends received from its subsidiaries. In addition to their future financial performance, the ability of PHI’s direct and indirect subsidiaries to pay dividends is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends and, in the case of ACE, the regulatory requirement that it obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%; (ii) the prior rights of holders of mortgage bonds and other long-term debt issued by the subsidiaries, and any other restrictions imposed in connection with the incurrence of liabilities; and (iii) certain provisions of ACE’s charter that impose restrictions on payment of common stock dividends for the benefit of preferred stockholders. Pepco, DPL and ACE have no shares of preferred stock outstanding at December 31, 2015. Currently, the capitalization ratio limitation to which ACE is subject and the restriction in the ACE charter do not limit ACE’s ability to pay common stock dividends. As further described in Note (10), “Debt,” PHI, Pepco, DPL and ACE have restrictions on total indebtedness in relation to total capitalization under the credit facility. PHI had approximately $617 million and $565 million of retained earnings free of restrictions at December 31, 2015 and 2014, respectively. These amounts represent the total retained earnings balances at those dates. The amount of restricted net assets for PHI’s consolidated subsidiaries at December 31, 2015 is $2,633 million. For the years ended December 31, 2015, 2014 and 2013, dividends paid by PHI’s subsidiaries were as follows: Subsidiary 2015 2014 2013 ( millions of dollars ) Pepco (paid to PHI) $ 146 $ 86 $ 46 DPL (paid to Conectiv) 92 100 30 ACE (paid to Conectiv) 12 26 60 Total $ 250 $ 212 $ 136 Equity Forward Transaction During 2012, PHI entered into an equity forward transaction in connection with a public offering of PHI common stock. Pursuant to the terms of this transaction, a forward counterparty borrowed 17,922,077 shares of PHI’s common stock from third parties and sold them to a group of underwriters for $19.25 per share, less an underwriting discount equal to $0.67375 per share. Under the terms of the equity forward transaction, upon physical settlement thereof, PHI was required to issue and deliver shares of PHI common stock to the forward counterparty at the then applicable forward sale price. The forward sale price was initially determined to be $18.57625 per share at the time the equity forward transaction was entered into and was subject to reduction from time to time in accordance with the terms of the equity forward transaction. PHI believed that the equity forward transaction substantially eliminated future equity price risk because the forward sale price was determinable as of the date that PHI entered into the equity forward transaction and was only reduced pursuant to the contractual terms of the equity forward transaction through the settlement date, which reductions were not affected by a future change in the market price of the PHI common stock. On February 27, 2013, PHI physically settled the equity forward at the then applicable forward sale price of $17.39 per share. The proceeds of approximately $312 million were used to repay outstanding commercial paper, a portion of which had been issued in order to make capital contributions to the utilities, and for general corporate purposes. Calculations of Earnings per Share of Common Stock The numerator and denominator for basic and diluted earnings per share of common stock calculations are shown below. For the Year Ended December 31, 2015 2014 2013 (millions of dollars, except per share data) Income (Numerator) Net income from continuing operations $ 318 $ 242 $ 110 Net income (loss) from discontinued operations 9 — (322 ) Net income (loss) $ 327 $ 242 $ (212 ) Shares (Denominator) (in millions): Weighted average shares outstanding for basic computation: Average shares outstanding 253 251 246 Adjustment to shares outstanding — — — Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock 253 251 246 Net effect of potentially dilutive shares (a) 1 1 — Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock 254 252 246 Basic earnings per share of common stock from continuing operations $ 1.25 $ 0.96 $ 0.45 Basic earnings (loss) per share of common stock from discontinued operations 0.04 — (1.31 ) Basic earnings (loss) per share $ 1.29 $ 0.96 $ (0.86 ) Diluted earnings per share of common stock from continuing operations $ 1.25 $ 0.96 $ 0.45 Diluted earnings (loss) per share of common stock from discontinued operations 0.04 — (1.31 ) Diluted earnings (loss) per share $ 1.29 $ 0.96 $ (0.86 ) (a) There were no options to purchase shares of common stock that were excluded from the calculation of diluted earnings per share for the years ended December 31, 2015, 2014 and 2013. Direct Stock Purchase and Dividend Reinvestment Plan PHI maintains a DRP through which participants may reinvest cash dividends. In addition, participants can make purchases of shares of PHI common stock through the investment of not less than $25 per purchase nor more than $300,000 each calendar year. Shares of common stock purchased through the DRP may be new shares, treasury shares held by PHI, or, at the election of PHI, shares purchased in the open market. Less than 1 million, approximately 1 million and 2 million new shares were issued and sold under the DRP in 2015, 2014 and 2013, respectively. Pepco Holdings Common Stock Reserved and Unissued The following table presents Pepco Holdings’ common stock reserved and unissued at December 31, 2015: Name of Plan Number of DRP 4,584,077 Pepco Holdings Long-Term Incentive Plan (a) 6,946,614 Pepco Holdings 2012 Long-Term Incentive Plan 7,136,961 Pepco Holdings Retirement Savings Plan 3,456,261 Total 22,123,913 (a) No further awards will be made under this plan. |
Preferred Stock
Preferred Stock | 12 Months Ended |
Dec. 31, 2015 | |
Equity [Abstract] | |
Preferred Stock | (13) PREFERRED STOCK In connection with entering into the Merger Agreement (as further described in Note (1), “Organization”), PHI entered into a Subscription Agreement with Exelon, dated April 29, 2014, pursuant to which PHI issued to Exelon 9,000 originally issued shares of Preferred Stock for a purchase price of $90 million on April 30, 2014. In connection with these agreements, Exelon also committed to purchase 1,800 originally issued shares of Preferred Stock for a purchase price of $18 million at the end of each 90-day period following April 29, 2014, up to a maximum of 18,000 shares of Preferred Stock for a maximum aggregate consideration of $180 million. In accordance with the Subscription Agreement, on each of July 29, 2014, October 27, 2014, January 26, 2015, April 27, 2015 and July 24, 2015, an additional 1,800 shares of Preferred Stock were issued by PHI to Exelon for an aggregate purchase price of $90 million. If the Merger closes or terminates for any reason, no additional shares of Preferred Stock will be issued pursuant to the Subscription Agreement. The holders of the Preferred Stock will be entitled to receive a cumulative, non-participating cash dividend of 0.1% per annum, payable quarterly, when, as and if declared by PHI’s board of directors. The proceeds from the issuance of the Preferred Stock are not subject to restrictions and are intended to serve as a prepayment of any applicable reverse termination fee payable from Exelon to PHI. The Preferred Stock will be redeemable on the terms and in the circumstances set forth in the Merger Agreement and the Subscription Agreement. If the Merger Agreement is terminated due to a Regulatory Termination, PHI will be able to redeem any issued and outstanding Preferred Stock at par value ($0.01 per share). If the Merger Agreement is terminated for any other reason, PHI will be required to redeem all issued and outstanding Preferred Stock at the purchase price of $10,000 per share, plus any unpaid accrued and accumulated dividends thereupon. PHI has excluded the Preferred Stock from equity at December 31, 2015 and 2014, since the Preferred Stock contains conditions for redemption that are not solely within the control of PHI. Management determined that the Preferred Stock contains embedded features requiring separate accounting consideration to reflect the potential value to PHI that any issued and outstanding Preferred Stock could be called and redeemed at a nominal par value upon a Regulatory Termination. The embedded call and redemption features on the shares of the Preferred Stock in the event of a Regulatory Termination are separately accounted for as derivatives. These Preferred Stock derivatives are valued at each reporting date using quantitative and qualitative factors, including management’s assessment of the likelihood of a Regulatory Termination. As of December 31, 2015, the fair value of the remaining derivative related to the Preferred Stock was estimated to be $18 million based on management’s updated assessment. The estimated fair value of the derivatives related to the Preferred Stock at December 31, 2014 was $3 million and has been included in current assets (Prepaid expenses and other) with a corresponding increase in Preferred Stock on the consolidated balance sheet at December 31, 2014. The $15 million increase in the fair value of the derivative has been included in Other income for the year ended December 31, 2015. |
Derivative Instruments and Hedg
Derivative Instruments and Hedging Activities | 12 Months Ended |
Dec. 31, 2015 | |
Derivative Instruments and Hedging Activities | (14) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES Derivative Instruments DPL uses derivative instruments in the form of futures primarily to reduce natural gas commodity price volatility and to limit its customers’ exposure to increases in the market price of natural gas under a hedging program approved by the DPSC. DPL uses these derivatives to manage the commodity price risk associated with its physical natural gas purchase contracts. The natural gas purchase contracts qualify as normal purchases, which are not required to be recorded in the financial statements until settled. All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all gains and losses related to hedging activities, are deferred under FASB guidance on regulated operations (ASC 980) until recovered from its customers through a fuel adjustment clause approved by the DPSC. In addition, included in derivative assets are PHI Preferred Stock derivatives which are further described in Note (13), “Preferred Stock.” ACE was ordered to enter into the SOCAs by the NJBPU, and under the SOCAs, ACE would have received payments from or made payments to electric generation facilities based on (i) the difference between the fixed price in the SOCAs and the price for capacity that clears PJM and (ii) ACE’s annual proportion of the total New Jersey load relative to the other EDCs in New Jersey. ACE began applying derivative accounting to two of its SOCAs as of June 30, 2012 because these generators cleared the 2015-2016 PJM capacity auction in May 2012. The fair value of the derivatives embedded in these SOCAs were deferred as Regulatory assets or Regulatory liabilities because the NJBPU allowed full recovery from ACE’s distribution customers for any payments made by ACE, and ACE’s distribution customers would be entitled to payments received by ACE. As further discussed in Note (7), “Regulatory Matters,” in light of a Federal district court order, which ruled that the SOCAs are void, invalid and unenforceable, and ACE’s subsequent termination of the SOCAs in the fourth quarter of 2013, ACE derecognized the derivative assets and derivative liabilities related to the SOCAs. The tables below identify the balance sheet location and fair values of derivative instruments as of December 31, 2015 and 2014: As of December 31, 2015 Balance Sheet Caption Derivatives Other Gross Derivative Effects of Net (millions of dollars) Derivative assets (current assets) $ — $ 18 $ 18 $ — $ 18 Derivative liabilities (current liabilities) — (2 ) (2 ) 2 — Net derivative asset $ — $ 16 $ 16 $ 2 $ 18 As of December 31, 2014 Balance Sheet Caption Derivatives Other Gross Derivative Effects of Net (millions of dollars) Derivative assets (current assets) $ — $ 3 $ 3 $ — $ 3 Derivative liabilities (current liabilities) — (4 ) (4 ) 4 — Net derivative (liability) asset $ — $ (1 ) $ (1 ) $ 4 $ 3 All derivative assets and liabilities available to be offset under master netting arrangements were netted as of December 31, 2015 and 2014. The amount of cash collateral that was offset against these derivative positions is as follows: December 31, December 31, (millions of dollars) Cash collateral pledged to counterparties with the right to reclaim (a) $ 2 $ 4 (a) Includes cash deposits on commodity brokerage accounts. As of December 31, 2015 and 2014, all PHI cash collateral pledged related to derivative instruments accounted for at fair value was entitled to be offset under master netting agreements. Derivatives Designated as Hedging Instruments Cash Flow Hedges Included in Accumulated Other Comprehensive Loss PHI also may use derivative instruments from time to time to mitigate the effects of fluctuating interest rates on debt issued in connection with the operation of its businesses. In June 2002, PHI entered into several treasury rate lock transactions in anticipation of the issuance of several series of fixed-rate debt commencing in August 2002. Upon issuance of the fixed-rate debt in August 2002, the treasury rate locks were terminated at a loss. The loss has been deferred in AOCL and is being recognized in interest expense over the life of the debt issued as interest payments are made. The tables below provide details regarding terminated cash flow hedges included in PHI’s consolidated balance sheets as of December 31, 2015 and 2014. The data in the following tables indicate the cumulative net loss after-tax related to terminated cash flow hedges by contract type included in AOCL, the portion of AOCL expected to be reclassified to income during the next 12 months, and the maximum hedge or deferral term: Contracts As of December 31, 2015 Maximum Term Accumulated Other Portion Expected to be Reclassified (millions of dollars) Interest rate $ 8 $ 1 200 months Contracts As of December 31, 2014 Maximum Term Accumulated Other Portion Expected (millions of dollars) Interest rate $ 9 $ 1 212 months Other Derivative Activity DPL has certain derivatives that are not in hedge accounting relationships and are not designated as normal purchases or normal sales. These derivatives are recorded at fair value on the consolidated balance sheets with the gain or loss for changes in fair value recorded in income. In addition, in accordance with FASB guidance on regulated operations (ASC 980), regulatory liabilities or regulatory assets of the same amount are recorded on the consolidated balance sheets and the recognition of the derivative gain or loss is deferred because of the DPSC-approved fuel adjustment clause for DPL’s derivatives and the NJBPU order pertaining to the ACE SOCA derivatives. During 2012, ACE had recognized derivative assets and derivative liabilities in connection with the SOCAs referred to in Note (7), “Regulatory Matters.” In 2013, the Federal district court issued an order as described in Note (7), “Regulatory Matters” which caused ACE to derecognize the derivative assets and derivatives liabilities related to the SOCAs in the fourth quarter of 2013. The following table shows the net unrealized and net realized derivative gains and losses arising during the period associated with these derivatives that were recognized in the consolidated statements of income (loss) (through Fuel and purchased energy expense) and that were also deferred as regulatory liabilities and regulatory assets, respectively, for the years ended December 31, 2015, 2014 and 2013: For the Year Ended December 31, 2015 2014 2013 (millions of dollars) Net unrealized (loss) gain arising during the period $ (3 ) $ (3 ) $ 4 Net realized (loss) gain recognized during the period (5 ) 2 (4 ) As of December 31, 2015 and 2014, the quantities and positions of DPL’s net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting were: December 31, 2015 December 31, 2014 Commodity Quantity Net Position Quantity Net Position DPL – Natural gas (one Million British Thermal Units) 4,190,000 Long 3,892,500 Long In addition, PHI recorded derivative assets for the embedded call and redemption features on the shares of Preferred Stock as further described in Note (13), “Preferred Stock.” The net unrealized gain arising during 2015 related to these derivative assets was $15 million and has been included in Other income. |
Delmarva Power & Light Co/De [Member] | |
Derivative Instruments and Hedging Activities | (12) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES DPL uses derivative instruments in the form of futures primarily to reduce natural gas commodity price volatility and to limit its customers’ exposure to increases in the market price of natural gas under a hedging program approved by the DPSC. DPL uses these derivatives to manage the commodity price risk associated with its physical natural gas purchase contracts. The natural gas purchase contracts qualify as normal purchases, which are not required to be recorded in the financial statements until settled. All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all gains and losses related to hedging activities, are deferred under FASB guidance on regulated operations (ASC 980) until recovered from its customers through a fuel adjustment clause approved by the DPSC. The tables below identify the balance sheet location and fair values of derivative instruments as of December 31, 2015 and 2014: As of December 31, 2015 Balance Sheet Caption Derivatives Designated as Hedging Instruments Other Derivative Instruments Gross Derivative Instruments Effects of Cash Collateral and Netting Net Derivative Instruments (millions of dollars) Derivative liabilities (current liabilities) $ — $ (2 ) $ (2 ) $ 2 $ — As of December 31, 2014 Balance Sheet Caption Derivatives Designated as Hedging Instruments Other Derivative Instruments Gross Derivative Instruments Effects of Cash Collateral and Netting Net Derivative Instruments (millions of dollars) Derivative liabilities (current liabilities) $ — $ (4 ) $ (4 ) $ 4 $ — All derivative liabilities available to be offset under master netting arrangements were netted as of December 31, 2015 and 2014. The amount of cash collateral that was offset against these derivative positions is as follows: December 31, December 31, (millions of dollars) Cash collateral pledged to counterparties with the right reclaim (a) $ 2 $ 4 (a) Includes cash deposits on commodity brokerage accounts. As of December 31, 2015 and 2014, all DPL cash collateral pledged related to derivative instruments accounted for at fair value was entitled to be offset under master netting agreements. Other Derivative Activity DPL has certain derivatives that are not in hedge accounting relationships and are not designated as normal purchases or normal sales. These derivatives are recorded at fair value on the balance sheets with the gain or loss for changes in the fair value recorded in income. In addition, in accordance with FASB guidance on regulated operations, regulatory liabilities or regulatory assets of the same amount are recorded on the balance sheets and the recognition of the derivative gain or loss is deferred because of the DPSC-approved fuel adjustment clause. The following table shows the net unrealized and net realized derivative gains and losses arising during the period associated with these derivatives that were recognized in the statements of income (through Purchased energy and Gas purchased expense) and that were also deferred as regulatory liabilities and regulatory assets, respectively, for the years ended December 31, 2015, 2014 and 2013: For the Year Ended December 31, 2015 2014 2013 (millions of dollars) Net unrealized (loss) gain arising during the period $ (3 ) $ (3 ) $ 1 Net realized (loss) gain recognized during the period (5 ) 2 (4 ) As of December 31, 2015 and 2014, the quantities and positions of DPL’s net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting were: December 31, 2015 December 31, 2014 Commodity Quantity Net Position Quantity Net Position Natural Gas (One Million British Thermal Units) 4,190,000 Long 3,892,500 Long |
Atlantic City Electric Co [Member] | |
Derivative Instruments and Hedging Activities | (11) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES ACE was ordered to enter into the SOCAs by the NJBPU, and under the SOCAs, ACE would have received payments from or made payments to electric generation facilities based on (i) the difference between the fixed price in the SOCAs and the price for capacity that clears PJM Interconnection, LLC (PJM) and (ii) ACE’s annual proportion of the total New Jersey load relative to the other EDCs in New Jersey. ACE began applying derivative accounting to two of its SOCAs as of June 30, 2012 because these generators cleared the 2015-2016 PJM capacity auction in May 2012. The fair value of the derivatives embedded in the SOCAs were deferred as Regulatory assets or Regulatory liabilities because the NJBPU allowed full recovery from ACE’s distribution customers for any payments made by ACE, and ACE’s distribution customers would be entitled to any payments received by ACE. As further discussed in Note (6), “Regulatory Matters,” in light of a Federal district court order, which ruled that the SOCAs are void, invalid and unenforceable, and ACE’s subsequent termination of the SOCAs in the fourth quarter of 2013, ACE derecognized the derivative assets and derivative liabilities related to the SOCAs. |
Fair Value Disclosures
Fair Value Disclosures | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value Disclosures | (15) FAIR VALUE DISCLOSURES Financial Instruments Measured at Fair Value on a Recurring Basis PHI applies FASB guidance on fair value measurement (ASC 820) that established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). PHI utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. Accordingly, PHI utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3). The following tables set forth, by level within the fair value hierarchy, PHI’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. PHI’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. Fair Value Measurements at December 31, 2015 Description Total Quoted Prices in Significant Significant (millions of dollars) ASSETS Derivative instruments Preferred stock $ 18 $ — $ — $ 18 Cash equivalents and restricted cash equivalents Treasury fund 42 42 — — Executive deferred compensation plan assets Money market funds and short-term investments 27 12 15 — Life insurance contracts 46 — 27 19 Total $ 133 $ 54 $ 42 $ 37 LIABILITIES Derivative instruments (b) Natural gas (c) $ 2 $ 2 $ — $ — Executive deferred compensation plan liabilities Life insurance contracts 30 — 30 — Total $ 32 $ 2 $ 30 $ — (a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2015. (b) The fair values of derivative liabilities reflect netting by counterparty before the impact of collateral. (c) Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC. Fair Value Measurements at December 31, 2014 Description Total Quoted Prices in Significant Significant (millions of dollars) ASSETS Derivative instruments Preferred stock $ 3 $ — $ — $ 3 Restricted cash equivalents Treasury fund 38 38 — — Executive deferred compensation plan assets Money market funds and short-term investments 35 14 21 — Life insurance contracts 46 — 27 19 Total $ 122 $ 52 $ 48 $ 22 LIABILITIES Derivative instruments (b) Natural gas (c) $ 4 $ 4 $ — $ — Executive deferred compensation plan liabilities Life insurance contracts 30 — 30 — Total $ 34 $ 4 $ 30 $ — (a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2014. (b) The fair values of derivative liabilities reflect netting by counterparty before the impact of collateral. (c) Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC. PHI classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation as follows: Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis, such as the Intercontinental Exchange. Level 2 – Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using broker quotes in liquid markets and other observable data. Level 2 also includes those financial instruments that are valued using methodologies that have been corroborated by observable market data through correlation or by other means. Significant assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Executive deferred compensation plan assets and liabilities categorized as level 2 consist of life insurance policies and certain employment agreement obligations. The life insurance policies are categorized as level 2 assets because they are valued based on the assets underlying the policies, which consist of short-term cash equivalents and fixed income securities that are priced using observable market data and can be liquidated for the value of the underlying assets as of December 31, 2015. The level 2 liability associated with the life insurance policies represents a deferred compensation obligation, the value of which is tracked via underlying insurance sub-accounts. The sub-accounts are designed to mirror existing mutual funds and money market funds that are observable and actively traded. The value of certain employment agreement obligations (which are included with life insurance contracts in the tables above) is derived using a discounted cash flow valuation technique. The discounted cash flow calculations are based on a known and certain stream of payments to be made over time that are discounted to determine their net present value. The primary variable input, the discount rate, is based on market-corroborated and observable published rates. These obligations have been classified as level 2 within the fair value hierarchy because the payment streams represent contractually known and certain amounts and the discount rate is based on published, observable data. Level 3 – Pricing inputs that are significant and generally less observable than those from objective sources. Level 3 includes those financial instruments that are valued using models or other valuation methodologies. Derivative instruments classified as level 3 include embedded call and redemption features on the Preferred Stock as further discussed in Note (13), “Preferred Stock.” Executive deferred compensation plan assets include certain life insurance policies that are valued using the cash surrender value of the policies, net of loans against those policies. The cash surrender values do not represent a quoted price in an active market; therefore, those inputs are unobservable and the policies are categorized as level 3. Cash surrender values are provided by third parties and reviewed by PHI for reasonableness. Reconciliations of the beginning and ending balances of PHI’s fair value measurements using significant unobservable inputs (Level 3) for the years ended December 31, 2015 and 2014 are shown below: Year Ended December 31, 2015 2014 Preferred Stock Life Insurance Preferred Stock Life (millions of dollars) Balance as of January 1 $ 3 $ 19 $ — $ 19 Total gains (losses) (realized and unrealized): Included in income 15 5 — 3 Included in accumulated other comprehensive loss — — — — Included in regulatory liabilities — — — — Purchases — — — — Issuances — (3 ) 3 (3 ) Settlements — (2 ) — — Transfers in (out) of level 3 — — — — Balance as of December 31 $ 18 $ 19 $ 3 $ 19 The breakdown of realized and unrealized gains on level 3 instruments included in income as a component of Other income or Other operation and maintenance expense for the periods below were as follows: Year Ended December 31, 2015 2014 (millions of dollars) Total net gains included in income for the period $ 20 $ 3 Change in unrealized gains relating to assets still held at reporting date $ 18 $ 3 Other Financial Instruments The estimated fair values of PHI’s Long-term debt instruments that are measured at amortized cost in PHI’s consolidated financial statements and the associated levels of the estimates within the fair value hierarchy as of December 31, 2015 and 2014 are shown in the tables below. As required by the fair value measurement guidance, debt instruments are classified in their entirety within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. PHI’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, which may affect the valuation of fair value debt instruments and their placement within the fair value hierarchy levels. The fair values of Long-term debt and Transition bonds categorized as level 2 are based on a blend of quoted prices for the debt and quoted prices for similar debt on the measurement date. The blend places more weight on current pricing information when determining the final fair value measurement. The fair value information is provided by brokers, and PHI reviews the methodologies and results. The fair value of Long-term debt categorized as level 3 is based on a discounted cash flow methodology using observable inputs, such as the U.S. Treasury yield, and unobservable inputs, such as credit spreads, because quoted prices for the debt or similar debt in active markets were insufficient. The Long-term project funding represents debt instruments issued by Pepco and Pepco Energy Services related to its energy savings and construction contracts. Long-term project funding is categorized as level 3 because PHI concluded that the amortized cost carrying amounts for these instruments approximate fair value, which does not represent a quoted price in an active market. Fair Value Measurements at December 31, 2015 Description Total Quoted Prices in Significant Significant (millions of dollars) LIABILITIES Debt instruments Long-term debt (a) $ 5,523 $ — $ 4,941 $ 582 Transition Bonds (b) 185 — 185 — Long-term project funding 5 — — 5 Total $ 5,713 $ — $ 5,126 $ 587 (a) The carrying amount for Long-term debt, net of unamortized discount, was $4,999 million as of December 31, 2015. (b) The carrying amount for Transition Bonds, including amounts due within one year, was $171 million as of December 31, 2015. Fair Value Measurements at December 31, 2014 Description Total Quoted Prices in Significant Significant (millions of dollars) LIABILITIES Debt instruments Long-term debt (a) $ 5,583 $ — $ 5,136 $ 447 Transition Bonds (b) 235 — 235 — Long-term project funding 28 — — 28 Total $ 5,846 $ — $ 5,371 $ 475 (a) The carrying amount for Long-term debt, net of unamortized discount, was $4,807 million as of December 31, 2014. (b) The carrying amount for Transition Bonds, including amounts due within one year, was $215 million as of December 31, 2014. The carrying amounts of all other financial instruments in the accompanying consolidated financial statements approximate fair value. |
Potomac Electric Power Co [Member] | |
Fair Value Disclosures | (11) FAIR VALUE DISCLOSURES Financial Instruments Measured at Fair Value on a Recurring Basis Pepco applies FASB guidance on fair value measurement (ASC 820) that established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Pepco utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. Accordingly, Pepco utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3). The following tables set forth, by level within the fair value hierarchy, Pepco’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Pepco’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. Fair Value Measurements at December 31, 2015 Description Total Quoted Prices in Significant Significant (millions of dollars) ASSETS Cash equivalents and restricted cash equivalents Treasury funds $ 2 $ 2 $ — $ — Executive deferred compensation plan assets Money market funds and short-term investments 26 11 15 — Life insurance contracts 42 — 23 19 Total $ 70 $ 13 $ 38 $ 19 LIABILITIES Executive deferred compensation plan liabilities Life insurance contracts $ 6 $ — $ 6 $ — Total $ 6 $ — $ 6 $ — (a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2015. Fair Value Measurements at December 31, 2014 Description Total Quoted Prices in Significant Significant (millions of dollars) ASSETS Restricted cash equivalents Treasury fund $ 5 $ 5 $ — $ — Executive deferred compensation plan assets Money market funds and short-term investments 34 13 21 — Life insurance contracts 41 — 23 18 Total $ 80 $ 18 $ 44 $ 18 LIABILITIES Executive deferred compensation plan liabilities Life insurance contracts $ 7 $ — $ 7 $ — Total $ 7 $ — $ 7 $ — (a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2014. Pepco classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation as follows: Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using broker quotes in liquid markets and other observable data. Level 2 also includes those financial instruments that are valued using methodologies that have been corroborated by observable market data through correlation or by other means. Significant assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Executive deferred compensation plan assets and liabilities categorized as level 2 consist of life insurance policies and certain employment agreement obligations. The life insurance policies are categorized as level 2 assets because they are valued based on the assets underlying the policies, which consist of short-term cash equivalents and fixed income securities that are priced using observable market data and can be liquidated for the value of the underlying assets as of December 31, 2015. The level 2 liability associated with the life insurance policies represents a deferred compensation obligation, the value of which is tracked via underlying insurance sub-accounts. The sub-accounts are designed to mirror existing mutual funds and money market funds that are observable and actively traded. The value of certain employment agreement obligations (which are included with life insurance contracts in the tables above) is derived using a discounted cash flow valuation technique. The discounted cash flow calculations are based on a known and certain stream of payments to be made over time that are discounted to determine their net present value. The primary variable input, the discount rate, is based on market-corroborated and observable published rates. These obligations have been classified as level 2 within the fair value hierarchy because the payment streams represent contractually known and certain amounts and the discount rate is based on published, observable data. Level 3 – Pricing inputs that are significant and generally less observable than those from objective sources. Level 3 includes those financial instruments that are valued using models or other valuation methodologies. Executive deferred compensation plan assets include certain life insurance policies that are valued using the cash surrender value of the policies, net of loans against those policies. The cash surrender values do not represent a quoted price in an active market; therefore, those inputs are unobservable and the policies are categorized as level 3. Cash surrender values are provided by third parties and reviewed by Pepco for reasonableness. Reconciliations of the beginning and ending balances of Pepco’s fair value measurements using significant unobservable inputs (Level 3) for the years ended December 31, 2015 and 2014 are shown below. 2015 2014 Life Insurance Life Insurance (millions of dollars) Balance as of January 1 $ 18 $ 18 Total gains (losses) (realized and unrealized): Included in income 5 3 Included in accumulated other comprehensive loss — — Purchases — — Issuances (3 ) (3 ) Settlements (1 ) — Transfers in (out) of level 3 — — Balance as of December 31 $ 19 $ 18 The breakdown of realized and unrealized gains on level 3 instruments included in income as a component of Other income or Other operation and maintenance expense for the periods below were as follows: Year Ended December 31, 2015 2014 (millions of dollars) Total gains included in income for the period $ 5 $ 3 Change in unrealized gains relating to assets still held at reporting date $ 3 $ 3 Other Financial Instruments The estimated fair values of Pepco’s Long-term debt instruments that are measured at amortized cost in Pepco’s financial statements and the associated levels of the estimates within the fair value hierarchy as of December 31, 2015 and 2014 are shown in the tables below. As required by the fair value measurement guidance, debt instruments are classified in their entirety within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. Pepco’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, which may affect the valuation of fair value debt instruments and their placement within the fair value hierarchy levels. The fair value of Long-term debt categorized as level 2 is based on a blend of quoted prices for the debt and quoted prices for similar debt on the measurement date. The blend places more weight on current pricing information when determining the final fair value measurement. The fair value information is provided by brokers, and Pepco reviews the methodologies and results. The Project funding represents debt instruments issued by Pepco related to its construction contracts. Project funding is categorized as level 3 because Pepco concluded that the amortized cost carrying amounts for these instruments approximate fair value, which does not represent a quoted price in an active market. Fair Value Measurements at December 31, 2015 Description Total Quoted Prices in Significant Significant (millions of dollars) LIABILITIES Debt instruments Long-term debt (a) $ 2,673 $ — $ 2,673 $ — (a) The carrying amount for Long-term debt, net of unamortized discount, was $2,332 million as of December 31, 2015. Fair Value Measurements at December 31, 2014 Description Total Quoted Prices in Significant Significant (millions of dollars) LIABILITIES Debt instruments Long-term debt (a) $ 2,624 $ — $ 2,624 $ — Project funding 12 — — 12 Total $ 2,636 $ — $ 2,624 $ 12 (a) The carrying amount for Long-term debt, net of unamortized discount, was $2,124 million as of December 31, 2014. The carrying amount of all other financial instruments in the accompanying financial statements approximate fair value. |
Delmarva Power & Light Co/De [Member] | |
Fair Value Disclosures | (13) FAIR VALUE DISCLOSURES Financial Instruments Measured at Fair Value on a Recurring Basis DPL applies FASB guidance on fair value measurement (ASC 820) that established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). DPL utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. Accordingly, DPL utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3). The following tables set forth, by level within the fair value hierarchy, DPL’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. DPL’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. Fair Value Measurements at December 31, 2015 Description Total Quoted Prices in Active Markets for Identical Instruments (Level 1) (a) Significant Other Observable Inputs (Level 2) (a) Significant Unobservable Inputs (Level 3) (millions of dollars) LIABILITIES Derivative instruments (b) Natural gas (c) $ 2 $ 2 $ — $ — Executive deferred compensation plan liabilities Life insurance contracts 1 — 1 — Total $ 3 $ 2 $ 1 $ — (a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2015. (b) The fair value of derivative liabilities reflect netting by counterparty before the impact of collateral. (c) Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC. Fair Value Measurements at December 31, 2014 Description Total Quoted Prices in Significant Significant (millions of dollars) ASSETS Restricted cash equivalents Treasury funds $ 5 $ 5 $ — $ — Executive deferred compensation plan assets Money market funds 1 1 — — Life insurance contracts 1 — — 1 Total $ 7 $ 6 $ — $ 1 LIABILITIES Derivative instruments (b) Natural gas (c) $ 4 $ 4 $ — $ — Executive deferred compensation plan liabilities Life insurance contracts 1 — 1 — Total $ 5 $ 4 $ 1 $ — (a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2014. (b) The fair value of derivative liabilities reflect netting by counterparty before the impact of collateral. (c) Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC. DPL classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation as follows: Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis, such as the Intercontinental Exchange. Level 2 – Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using broker quotes in liquid markets and other observable data. Level 2 also includes those financial instruments that are valued using methodologies that have been corroborated by observable market data through correlation or by other means. Significant assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Level 2 executive deferred compensation plan liabilities associated with the life insurance policies represent a deferred compensation obligation, the value of which is tracked via underlying insurance sub-accounts. The sub-accounts are designed to mirror existing mutual funds and money market funds that are observable and actively traded. Level 3 – Pricing inputs that are significant and generally less observable than those from objective sources. Level 3 includes those financial instruments that are valued using models or other valuation methodologies. Executive deferred compensation plan assets include certain life insurance policies that are valued using the cash surrender value of the policies, net of loans against those policies. The cash surrender values do not represent a quoted price in an active market; therefore, those inputs are unobservable and the policies are categorized as level 3. Cash surrender values are provided by third parties and reviewed by DPL for reasonableness. Reconciliations of the beginning and ending balances of DPL’s fair value measurements using significant unobservable inputs (Level 3) for the years ended December 31, 2015 and 2014 are shown below: Year Ended Year Ended Life Insurance Contracts Life Insurance Contracts (millions of dollars) Balance as of January 1 $ 1 $ 1 Total gains (losses) (realized and unrealized): Included in income — — Included in accumulated other comprehensive loss — — Included in regulatory liabilities — — Purchases — — Issuances — — Settlements (1 ) — Transfers in (out) of Level 3 — — Balance as of December 31 $ — $ 1 Other Financial Instruments The estimated fair values of DPL’s Long-term debt instruments that are measured at amortized cost in DPL’s financial statements and the associated levels of the estimates within the fair value hierarchy as of December 31, 2015 and 2014 are shown in the tables below. As required by the fair value measurement guidance, debt instruments are classified in their entirety within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. DPL’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, which may affect the valuation of fair value debt instruments and their placement within the fair value hierarchy levels. The fair value of Long-term debt categorized as level 2 is based on a blend of quoted prices for the debt and quoted prices for similar debt on the measurement date. The blend places more weight on current pricing information when determining the final fair value measurement. The fair value information is provided by brokers, and DPL reviews the methodologies and results. The fair value of Long-term debt categorized as level 3 is based on a discounted cash flow methodology using observable inputs, such as the U.S. Treasury yield, and unobservable inputs, such as credit spreads, because quoted prices for the debt or similar debt in active markets were insufficient. Fair Value Measurements at December 31, 2015 Description Total Quoted Prices in Significant Significant (millions of dollars) LIABILITIES Debt instruments Long-term debt (a) $ 1,183 $ — $ 1,080 $ 103 (a) The carrying amount for Long-term debt, including unamortized premium, was $1,170 million as of December 31, 2015. Fair Value Measurements at December 31, 2014 Description Total Quoted Prices in Significant Significant (millions of dollars) LIABILITIES Debt instruments Long-term debt (a) $ 1,123 $ — $ 1,016 $ 107 (a) The carrying amount for Long-term debt, including unamortized premium, was $1,071 million as of December 31, 2014. The carrying amounts of all other financial instruments in the accompanying financial statements approximate fair value. |
Atlantic City Electric Co [Member] | |
Fair Value Disclosures | (12) FAIR VALUE DISCLOSURES Financial Instruments Measured at Fair Value on a Recurring Basis ACE applies FASB guidance on fair value measurement (ASC 820) that established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). ACE utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. Accordingly, ACE utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3). The following tables set forth by level within the fair value hierarchy ACE’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. ACE’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. Fair Value Measurements at December 31, 2015 Description Total Quoted Prices in Active Markets for Identical Instruments (Level 1) (a) Significant Other Observable Inputs (Level 2) (a) Significant Unobservable Inputs (Level 3) (millions of dollars) ASSETS Cash equivalents and restricted cash equivalents Treasury funds $ 30 $ 30 $ — $ — (a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2015. Fair Value Measurements at December 31, 2014 Description Total Quoted Prices in Active Markets for Identical Instruments (Level 1) (a) Significant Other Observable Inputs (Level 2) (a) Significant Unobservable Inputs (Level 3) (millions of dollars) ASSETS Cash equivalents and restricted cash equivalents Treasury funds $ 24 $ 24 $ — $ — (a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2014. ACE classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation as follows: Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using broker quotes in liquid markets and other observable data. Level 2 also includes those financial instruments that are valued using methodologies that have been corroborated by observable market data through correlation or by other means. Significant assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Level 3 – Pricing inputs that are significant and generally less observable than those from objective sources. Level 3 includes those financial instruments that are valued using models or other valuation methodologies. Other Financial Instruments The estimated fair values of ACE’s Long-term debt instruments that are measured at amortized cost in ACE’s consolidated financial statements and the associated levels of the estimates within the fair value hierarchy as of December 31, 2015 and 2014 are shown in the tables below. As required by the fair value measurement guidance, debt instruments are classified in their entirety within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. ACE’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, which may affect the valuation of fair value debt instruments and their placement within the fair value hierarchy levels. The fair values of Long-term debt and Transition bonds categorized as level 2 are based on a blend of quoted prices for the debt and quoted prices for similar debt on the measurement date. The blend places more weight on current pricing information when determining the final fair value measurement. The fair value information is provided by brokers, and ACE reviews the methodologies and results. The fair value of Long-term debt categorized as level 3 is based on a discounted cash flow methodology using observable inputs, such as the U.S. Treasury yield, and unobservable inputs, such as credit spreads, because quoted prices for the debt or similar debt in active markets were insufficient. Fair Value Measurements at December 31, 2015 Description Total Quoted Prices in Significant Significant (millions of dollars) LIABILITIES Debt instruments Long-term debt (a) $ 1,140 $ — $ 860 $ 280 Transition Bonds (b) 185 — 185 — Total $ 1,325 $ — $ 1,045 $ 280 (a) The carrying amount for Long-term debt, net of unamortized discount, was $1,038 million as of December 31, 2015. (b) The carrying amount for Transition Bonds, including amounts due within one year, was $171 million as of December 31, 2015. Fair Value Measurements at December 31, 2014 Description Total Quoted Prices in Significant Significant (millions of dollars) LIABILITIES Debt instruments Long-term debt (a) $ 1,035 $ — $ 903 $ 132 Transition Bonds (b) 235 — 235 — Total $ 1,270 $ — $ 1,138 $ 132 (a) The carrying amount for Long-term debt, net of unamortized discount, was $903 million as of December 31, 2014. (b) The carrying amount for Transition Bonds, including amounts due within one year, was $215 million as of December 31, 2014. The carrying amounts of all other financial instruments in the accompanying consolidated financial statements approximate fair value. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2015 | |
Commitments and Contingencies | (16) COMMITMENTS AND CONTINGENCIES General Litigation From time to time, PHI and its subsidiaries are named as defendants in litigation, usually relating to general liability or auto liability claims that resulted in personal injury or property damage to third parties. PHI and each of its subsidiaries are self-insured against such claims up to a certain self-insured retention amount and maintain insurance coverage against such claims at higher levels, to the extent deemed prudent by management. In addition, PHI’s contracts with its vendors generally require the vendors to name PHI and/or its subsidiaries as additional insureds for the amounts at least equal to PHI’s self-insured retention. Further, PHI’s contracts with its vendors require the vendors to indemnify PHI for various acts and activities that may give rise to claims against PHI. Loss contingency liabilities for both asserted and unasserted claims are recognized if it is probable that a loss will result from such a claim and if the amounts of the losses can be reasonably estimated. Although the outcome of the claims and proceedings cannot be predicted with any certainty, management believes that there are no existing claims or proceedings that are likely to have a material adverse effect on PHI’s or its subsidiaries’ financial condition, results of operations or cash flows. At December 31, 2015, PHI had recorded estimated loss contingency liabilities for general litigation totaling approximately $12 million. Environmental Matters PHI, through its subsidiaries, is subject to regulation by various federal, regional, state and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal and limitations on land use. Although penalties assessed for violations of environmental laws and regulations are not recoverable from customers of PHI’s utility subsidiaries, environmental clean-up costs incurred by Pepco, DPL and ACE generally are included by each company in its respective cost of service for ratemaking purposes. The total accrued liabilities for the environmental contingencies described below of PHI and its subsidiaries at December 31, 2015 are summarized as follows: Legacy Generation Transmission Regulated Non-Regulated Total (millions of dollars) Balance as of January 1 $ 17 $ 6 $ 5 $ 28 Accruals 7 3 — 10 Payments (4 ) (1 ) — (5 ) Balance as of December 31 20 8 5 33 Less amounts in Other Current Liabilities 3 1 — 4 Amounts in Other Deferred Credits $ 17 $ 7 $ 5 $ 29 Conectiv Energy Wholesale Power Generation Sites In July 2010, PHI sold the wholesale power generation business of Conectiv Energy Holdings, Inc. and substantially all of its subsidiaries (Conectiv Energy) to Calpine Corporation (Calpine). Under New Jersey’s Industrial Site Recovery Act (ISRA), the transfer of ownership triggered an obligation on the part of Conectiv Energy to remediate any environmental contamination at each of the nine Conectiv Energy generating facility sites located in New Jersey. Under the terms of the sale, Calpine has assumed responsibility for performing the ISRA-required remediation and for the payment of all related ISRA compliance costs up to $10 million. PHI is obligated to indemnify Calpine for any ISRA compliance remediation costs in excess of $10 million. According to PHI’s estimates, the costs of ISRA-required remediation activities at the nine generating facility sites located in New Jersey are in the range of approximately $7 million to $18 million. The amount accrued by PHI for the ISRA-required remediation activities at the nine generating facility sites is included in the table above in the column entitled “Legacy Generation – Non-Regulated.” In September 2011, PHI received a request for data from the U.S. Environmental Protection Agency (EPA) regarding operations at the Deepwater generating facility in New Jersey (which was included in the sale to Calpine) between February 2004 and July 1, 2010, to demonstrate compliance with the Clean Air Act’s new source review permitting program. PHI responded to the data request. Under the terms of the Calpine sale, PHI is obligated to indemnify Calpine for any failure of PHI, on or prior to the closing date of the sale, to comply with environmental laws attributable to the construction of new, or modification of existing, sources of air emissions. At this time, PHI does not expect that any financial consequences that could arise from this inquiry would have a material adverse effect on its consolidated financial condition, results of operations or cash flows. Franklin Slag Pile Site In November 2008, ACE received a general notice letter from EPA concerning the Franklin Slag Pile site in Philadelphia, Pennsylvania, asserting that ACE is a potentially responsible party (PRP) that may have liability for clean-up costs with respect to the site and for the costs of implementing an EPA-mandated remedy. EPA’s claims are based on ACE’s sale of boiler slag from the B.L. England generating facility, then owned by ACE, to MDC Industries, Inc. (MDC) during the period from June 1978 to May 1983. EPA claims that the boiler slag ACE sold to MDC contained copper and lead, which are hazardous substances under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA), and that the sales transactions may have constituted an arrangement for the disposal or treatment of hazardous substances at the site, which could be a basis for liability under CERCLA. The EPA letter also states that, as of the date of the letter, EPA’s expenditures for response measures at the site have exceeded $6 million. EPA’s feasibility study (FS) for this site conducted in 2007 identified a range of alternatives for permanent remedial measures with varying cost estimates, and the estimated cost of EPA’s preferred alternative is approximately $6 million. ACE believes that the B.L. England boiler slag sold to MDC was a valuable material with various industrial applications and, therefore, the sale was not an arrangement for the disposal or treatment of any hazardous substances as would be necessary to constitute a basis for liability under CERCLA. ACE intends to contest any claims to the contrary made by EPA. In a May 2009 decision arising under CERCLA, which did not involve ACE, the U.S. Supreme Court rejected an EPA argument that the sale of a useful product constituted an arrangement for disposal or treatment of hazardous substances. While this decision supports ACE’s position, at this time ACE cannot predict how EPA will proceed with respect to the Franklin Slag Pile site, or what portion, if any, of the Franklin Slag Pile site response costs EPA would seek to recover from ACE. Costs to resolve this matter are not expected to be material and are expensed as incurred. Peck Iron and Metal Site EPA informed Pepco in a May 2009 letter that Pepco may be a PRP under CERCLA with respect to the cleanup of the Peck Iron and Metal site in Portsmouth, Virginia, and for costs EPA has incurred in cleaning up the site. The EPA letter states that Peck Iron and Metal purchased, processed, stored and shipped metal scrap from military bases, governmental agencies and businesses and that the Peck Iron and Metal scrap operations resulted in the improper storage and disposal of hazardous substances. EPA bases its allegation that Pepco arranged for disposal or treatment of hazardous substances sent to the site on information provided by former Peck Iron and Metal personnel, who informed EPA that Pepco was a customer at the site. Pepco has advised EPA by letter that its records show no evidence of any sale of scrap metal by Pepco to the site. Even if EPA has such records and such sales did occur, Pepco believes that any such scrap metal sales may be entitled to the recyclable material exemption from CERCLA liability. In September 2011, EPA initiated a remedial investigation/feasibility study (RI/FS) for the site using federal funds. Pepco cannot at this time estimate an amount or range of reasonably possible loss associated with this RI/FS, any remediation activities to be performed at the site or any other costs that EPA might seek to impose on Pepco. Benning Road Site Contamination of Lower Anacostia River In September 2010, PHI received a letter from EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site was formerly the location of a Pepco Energy Services electric generating facility. That generating facility was deactivated in June 2012 and plant structure demolition was completed in July 2015. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. The principal contaminants allegedly of concern are polychlorinated biphenyls and polycyclic aromatic hydrocarbons. In December 2011, the U.S. District Court for the District of Columbia approved a consent decree entered into by Pepco and Pepco Energy Services with the District of Columbia Department of Energy and Environment (DOEE) (formerly the District of Columbia Department of the Environment), which requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10 to 15 acre portion of the adjacent Anacostia River. The RI/FS will form the basis for the remedial actions for the Benning Road site and for the Anacostia River sediment associated with the site. The consent decree does not obligate Pepco or Pepco Energy Services to pay for or perform any remediation work, but it is anticipated that DOEE will look to Pepco and Pepco Energy Services to assume responsibility for cleanup of any conditions in the river that are determined to be attributable to past activities at the Benning Road site. The initial remedial investigation field work began in January 2013 and was completed in December 2014. In addition, in conjunction with the power plant demolition activities, Pepco and Pepco Energy Services collected soil samples adjacent to and beneath the concrete basins for the dismantled cooling towers for the generating facility. This sampling showed localized areas of soil contamination associated with the cooling tower basins, and, beginning in the first quarter of 2016, Pepco and Pepco Energy Services expect to implement a plan approved by DOEE to remove contaminated soil in conjunction with the demolition and removal of the concrete basins. On April 30, 2015, Pepco and Pepco Energy Services submitted a draft Remedial Investigation (RI) Report to DOEE. After review, DOEE determined that additional field investigation and data analysis is required to complete the RI process (much of which is beyond the scope of the original DOEE-approved RI work plan). In the meantime, Pepco and Pepco Energy Services will revise the draft RI Report as appropriate to address DOEE’s comments and DOEE will make the draft RI available for public review during the first quarter of 2016. The additional field investigation and data analysis will proceed later in 2016 according to a schedule to be developed by Pepco and Pepco Energy Services and approved by DOEE. Once the additional RI work has been completed, Pepco and Pepco Energy Services will issue a draft “final” RI report for review and comment by DOEE and the public. Pepco and Pepco Energy Services will then proceed with an FS to evaluate possible remedial alternatives. This effort also may include a treatability study to evaluate the effectiveness of potential remedial options. Once the FS has been completed, Pepco and Pepco Energy Services will prepare and submit a draft FS Report for review and comment by DOEE and the public. Thereafter, Pepco and Pepco Energy Services will revise the draft FS Report as appropriate to address comments received and will submit a final FS Report to DOEE. Upon DOEE’s approval of the final RI and FS Reports, Pepco and Pepco Energy Services will have satisfied their obligations under the consent decree. At that point, DOEE will prepare a Proposed Plan regarding further response actions based on the results of the RI/FS. After considering public comment on the Proposed Plan, DOEE will issue a Record of Decision identifying any further response actions determined to be necessary. DOEE, Pepco and Pepco Energy Services must submit their next joint status report to the court regarding progress on the RI/FS by May 24, 2016. PHI, Pepco and Pepco Energy Services have determined that a loss associated with this matter for PHI, Pepco and Pepco Energy Services is probable and have estimated that the costs of remediation are in the range of approximately $9 million to $13 million. The remediation costs accrued for this matter are included in the table above in the columns entitled “Transmission and Distribution,” “Legacy Generation – Regulated,” and “Legacy Generation – Non-Regulated.” NPDES Permit Limit Exceedances Pepco holds a National Pollutant Discharge Elimination System (NPDES) permit issued by EPA with a July 19, 2009 effective date, which authorizes discharges from the Benning Road site, including the Pepco Energy Services generating facility previously located on the site that was deactivated in 2012 and has been demolished. The 2009 permit for the first time imposed numerical limits on the allowable concentration of certain metals in storm water discharged from the site into the Anacostia River as determined by EPA to be necessary to meet the applicable District of Columbia surface water quality standards. The permit contemplated that Pepco would meet these limits over time through the use of best management practices (BMPs). As of December 2012, Pepco completed the implementation of the first two phases of BMPs identified in a plan approved by EPA (consisting principally of installing metal absorbing filters to capture contaminants at storm water inlets, removing stored equipment from areas exposed to the weather, covering and painting exposed metal pipes, and covering and cleaning dumpsters). These measures were effective in reducing metal concentrations in storm water discharges, but were not sufficient to meet all of the numerical limits for metals. Most of the quarterly monitoring results since the issuance of the permit have shown exceedances of the limits for copper and zinc, as well as occasional exceedances for iron and lead. The NPDES permit was due to expire on June 19, 2014. Pepco submitted a permit renewal application on December 17, 2013. In November 2014, EPA advised Pepco that it will not renew the permit until the Benning Road site has come into compliance with the existing permit limits. The current permit remains in effect pending EPA’s action on the renewal application. In December 2014, Pepco submitted a plan to EPA to implement the third phase of BMPs recommended in the original permit compliance plan with the objective of achieving full compliance with the permit limits for metals by the end of 2015 and Pepco immediately began to implement the additional BMPs in accordance with the plan. On September 1, 2015, Pepco submitted a report to EPA on the status of implementation of the third phase of BMPs. As of that date, Pepco had fully implemented most of the elements of the Phase 3 plan, including installation of upgraded storm water inlet controls (filters and booms), enhanced inspection and maintenance of inlets, removal of materials and equipment from exposure to storm water, and removal of accumulated sediments from the underground storm drains. The sampling results from the third quarter of 2015 showed compliance with all of the permit limits. The sampling results from the fourth quarter of 2015 showed compliance with all but a single permit limit for metals; the concentration of copper was below the daily maximum limit but exceeded the monthly average limit. As confirmed by this latest sampling, because the permit limits are low and site conditions are subject to variation, Pepco has concluded that some form of storm water treatment prior to discharge will be necessary to ensure ongoing compliance with all permit limits and has begun the process of evaluating treatment options. The nature and scope of the necessary treatment system, and the amount of the associated capital expenditures, will not be known until Pepco has completed the evaluation and design process. Pepco has been engaged in discussions with representatives from EPA and the DOJ regarding permit compliance. On October 30, 2015, EPA filed a Clean Water Act civil enforcement action against Pepco in federal district court. Pepco expects that this enforcement action will be resolved through a consent decree that will (i) establish further requirements to achieve compliance with the permit limits, including the design and installation of an appropriate storm water treatment system as noted above, and (ii) include civil penalties for past noncompliance. The amount of such penalties is not known or estimable at this time and Pepco does not expect the amount of such penalties to have a material adverse effect on PHI’s consolidated financial condition, results of operations or cash flows. Pepco and EPA are currently in discussions regarding the terms of the contemplated consent decree, and it is anticipated that the parties will finalize the consent decree during the first half of 2016. In response to a joint motion by the parties, the court has extended the deadline for Pepco to answer the complaint to May 16, 2016, to give the parties time to work towards agreement on the terms of a consent decree. The parties contemplate seeking a further extension if necessary to complete their negotiations. Once executed by the parties, the consent decree will be filed with the court for review and approval following a period for public comment. Potomac River Mineral Oil Release In January 2011, a coupling failure on a transformer cooler pipe resulted in a release of non-toxic mineral oil at Pepco’s Potomac River substation in Alexandria, Virginia. An overflow of an underground secondary containment reservoir resulted in approximately 4,500 gallons of mineral oil flowing into the Potomac River. In March 2014, Pepco and DOEE entered into a consent decree to resolve a threatened DOEE enforcement action, the terms of which include a combination of a civil penalty and a Supplemental Environmental Project (SEP) with a total cost to Pepco of $875,000. The consent decree was approved and entered by the District of Columbia Superior Court on April 4, 2014. Pepco has paid the $250,000 civil penalty imposed under the consent decree and, pursuant to the consent decree, has made a one-time donation in the amount of $25,000 to the Northeast Environmental Enforcement Training Fund, Inc., a non-profit organization that funds scholarships for environmental enforcement training. The consent decree confirmed that no further actions are required by Pepco to investigate, assess or remediate impacts to the river from the mineral oil release. To implement the SEP, Pepco has entered into an agreement with Living Classrooms Foundation, Inc., a non-profit educational organization, pursuant to which Pepco will provide $600,000 to fund the design, installation and operation of a trash collection system at a storm water outfall that drains to the Anacostia River. DOEE approved the design for the trash collection system and efforts to secure necessary permits are in progress. Pepco expects that this system will be constructed and placed into operation by the end of 2016, which will satisfy Pepco’s obligations under the consent decree. On September 11, 2015, Pepco and DOEE filed a joint report with the D.C. Superior Court on the status of the trash cage project and other elements of the consent decree. The court accepted that report and scheduled the next status hearing in this matter for September 23, 2016. The consent decree did not resolve potential claims under federal law for natural resource damages resulting from the mineral oil release. Pepco has engaged in separate discussions with DOEE and the federal resource trustees regarding the settlement of a possible natural resource damages claim under federal law. In July 2013, Pepco submitted a natural resource damage assessment to DOEE and the federal trustees that proposed monetary compensation for such damages in the range of $106,000 to $161,000. By letter dated September 16, 2015, the U.S. Department of Interior, on behalf of the trustees, made a confidential counter-proposal for settlement of the natural resource damage claim. Pepco has engaged in subsequent discussions with the trustees and believes that the parties are close to reaching an agreement to settle the claims. Based on the discussions to date, PHI and Pepco do not believe that the resolution of the natural resource damages claim will have a material adverse effect on their respective financial condition, results of operations or cash flows. As a result of the mineral oil release, Pepco implemented certain interim operational changes to the secondary containment systems at the facility, which involve pumping accumulated storm water to an above-ground holding tank for off-site disposal. Pepco is continuing to use the above-ground holding tank to manage storm water from the secondary containment system while it evaluates other technical and regulatory options. The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.” Metal Bank Site In the first quarter of 2013, the National Oceanic and Atmospheric Administration (NOAA) contacted Pepco and DPL on behalf of itself and other federal and state trustees to request that Pepco and DPL execute a tolling agreement to facilitate settlement negotiations concerning natural resource damages allegedly caused by releases of hazardous substances, including polychlorinated biphenyls, at the Metal Bank Cottman Avenue Superfund Site located in Philadelphia, Pennsylvania. Pepco and DPL executed a tolling agreement, which has been extended to March 15, 2016, and will continue settlement discussions with the NOAA, the trustees and other PRPs. The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.” Brandywine Fly Ash Disposal Site In February 2013, Pepco received a letter from the Maryland Department of the Environment (MDE) requesting that Pepco investigate the extent of waste on a Pepco right-of-way that traverses the Brandywine fly ash disposal site in Brandywine, Prince George’s County, Maryland, owned by NRG Energy, Inc. (as successor to GenOn MD Ash Management, LLC) (NRG). In July 2013, while reserving its rights and related defenses under a 2000 agreement covering the sale of this site, Pepco indicated its willingness to investigate the extent of, and propose an appropriate closure plan to address, ash on the right-of-way. Pepco submitted a schedule for development of a closure plan to MDE on September 30, 2013 and, by letter dated October 18, 2013, MDE approved the schedule. PHI and Pepco have determined that a loss associated with this matter for PHI and Pepco is probable and have estimated that the costs for implementation of a closure plan and cap on the site are in the range of approximately $3 million to $6 million. PHI and Pepco believe that the costs incurred in this matter will be recoverable from NRG under the 2000 sale agreement. The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.” Virginia Department of Environmental Quality Notice of Violation On February 3, 2015, the Virginia Department of Environmental Quality (VDEQ) issued a notice of violation (NOV) to DPL in connection with alleged violations of state water control laws and regulations associated with recent construction activities undertaken to replace certain transmission facilities. The NOV informed DPL of information on which VDEQ may rely to institute an administrative or judicial enforcement action, requested a meeting, and stated that DPL may be asked to enter into a consent order to formalize a plan and schedule of corrective action and settle any outstanding issues regarding the matter including the assessment of civil charges. At a February 20, 2015 meeting, VDEQ confirmed that the NOV would be resolved through a consent order, which will require the payment of a penalty, but did not specify the potential penalty amount. DPL will pursue recovery of the restoration costs for this matter from the contractor responsible for the vegetation management activities that gave rise to the alleged violations. PHI and DPL have substantially completed all remediation activities related to this matter and do not believe that the potential penalty to resolve this matter will have a material adverse effect on their respective financial condition, results of operations or cash flows. Rock Creek Mineral Oil Release In late August 2015, a Pepco underground transmission line in the District of Columbia suffered a breach, resulting in the release of non-toxic mineral oil surrounding the transmission line into the surrounding soil, and a small amount also reached Rock Creek through a storm drain. Pepco notified regulatory authorities, and Pepco and its spill response contractors placed booms in Rock Creek, blocked the storm drain to prevent the release of mineral oil into the creek and commenced remediation of soil around the transmission line and the Rock Creek shoreline. Pepco estimates that approximately 6,100 gallons of mineral oil were released and that its remediation efforts recovered approximately 80 percent of the amount released. Pepco’s remediation efforts are ongoing under the direction of the DOEE and in collaboration with the National Park Service, the Smithsonian Institution/National Zoo and EPA. Pepco’s investigation presently indicates that the damage to Pepco’s facilities occurred prior to the release of mineral oil when third-party excavators struck the Pepco underground transmission line while installing cable for another utility. To the extent recovery is available against any party who contributed to this loss, PHI and Pepco will pursue such action. PHI and Pepco continue to investigate the cause of the incident, the parties involved, and legal responsibility under District of Columbia law, but do not believe that the remediation costs to resolve this matter will have a material adverse effect on their respective financial condition, results of operations or cash flows. PHI’s Cross-Border Energy Lease Investments PHI held a portfolio of cross-border energy lease investments involving public utility assets located outside of the United States. Each of these investments was comprised of multiple leases and was structured as a sale and leaseback transaction commonly referred to by the IRS as a SILO transaction. During the second and third quarters of 2013, PHI terminated early all of its remaining cross-border energy lease investments. Since 2005, PHI’s former cross-border energy lease investments have been under examination by the IRS as part of the PHI federal income tax audits. In connection with the audit of PHI’s 2001-2002 income tax returns, the IRS disallowed the depreciation and interest deductions in excess of rental income claimed by PHI for six of the eight lease investments and, in connection with the audits of PHI’s 2003-2005 and 2006-2008 income tax returns, the IRS disallowed such deductions in excess of rental income for all eight of the lease investments. In addition, the IRS has sought to recharacterize each of the leases as a loan transaction in each of the years under audit as to which PHI would be subject to original issue discount income. PHI had disagreed with the IRS’ proposed adjustments to the 2001-2008 income tax returns and filed protests of these findings for each year with the Office of Appeals of the IRS. In November 2010, PHI entered into a settlement agreement with the IRS for the 2001 and 2002 tax years for the purpose of commencing litigation associated with this matter and subsequently filed refund claims in July 2011 for the disallowed tax deductions relating to the leases for these years. In January 2011, as part of this settlement, PHI paid $74 million of additional tax for 2001 and 2002, penalties of $1 million, and $28 million in interest associated with the disallowed deductions. Since the July 2011 refund claims were not approved by the IRS within the statutory six-month period, in January 2012 PHI filed complaints in the U.S. Court of Federal Claims seeking recovery of the tax payment, interest and penalties. On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States Assuming that the IRS were to be successful in disallowing 100% of the tax benefits associated with these lease investments and recharacterize these lease investments as loans, PHI estimated that, as of March 31, 2013, it would have been obligated to pay approximately $192 million in additional federal taxes (net of the $74 million tax payment described above) and approximately $50 million of interest on the additional federal taxes. These amounts, totaling $242 million, were estimated after consideration of certain tax benefits arising from matters unrelated to the leases that would offset the taxes and interest due, including PHI’s best estimate of the expected resolution of other uncertain and effectively settled tax positions, the carrying back and carrying forward of any existing net operating losses, and the application of certain amounts paid in advance to the IRS. In order to mitigate PHI’s ongoing interest costs associated with the $242 million estimate of additional taxes and interest, PHI made an advanced payment to the IRS of $242 million in the first quarter of 2013. This advanced payment was funded from currently available sources of liquidity and short-term borrowings. A portion of the proceeds from lease terminations effected during the second and third quarters of 2013 was used to repay the short-term borrowings utilized to fund the advanced payment. On November 18, 2015, PHI entered into the Global Tax Settlement with the IRS and the DOJ to provide for the resolution of the tax treatment of its previously held cross-border energy lease investments structured as SILO transactions. As a result of the Global Tax Settlement, PHI and the DOJ filed stipulations of dismissal regarding the litigation in the U.S. Court of Federal Claims. The Court dismissed the complaint on November 20, 2015. For additional discussion on the Global Tax Settlement with the IRS, see Note (11), “Income Taxes.” Third Party Guarantees, Indemnifications, and Off-Balance Sheet Arrangements PHI and certain of its subsidiaries have various financial and performance guarantees and indemnification obligations that they have entered into in the normal course of business to facilitate commercial transactions with third parties as discussed below. As of December 31, 2015, PHI and its subsidiaries were parties to a variety of agreements pursuant to which they were guarantors. The commitments and obligations were as follows: Guarantor PHI Pepco DPL ACE Total (millions of dollars) Guarantees associated with disposal of Conectiv Energy assets (a) $ 13 $ — $ — $ — $ 13 Guaranteed lease residual values (b) 3 5 6 5 19 Total $ 16 $ 5 $ 6 $ 5 $ 32 (a) Represents guarantees by PHI of Conectiv Energy’s derivative portfolio transferred in connection with the disposition of Conectiv Energy’s wholesale business. The derivative portfolio guarantee is currently $13 million and covers Conectiv Energy’s performance prior to the assignment. The guarantee was terminated in January 2016. (b) Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $52 million, $9 million of which is a guarantee by PHI, $13 million by Pepco, $16 million by DPL and $14 million by ACE. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote. PHI and certain of its subsidiaries have entered in |
Potomac Electric Power Co [Member] | |
Commitments and Contingencies | (12) COMMITMENTS AND CONTINGENCIES General Litigation From time to time, Pepco is named as a defendant in litigation, usually relating to general liability or auto liability claims that resulted in personal injury or property damage to third parties. Pepco is self-insured against such claims up to a certain self-insured retention amount and maintains insurance coverage against such claims at higher levels, to the extent deemed prudent by management. In addition, Pepco’s contracts with its vendors generally require the vendors to name Pepco as an additional insured for the amount at least equal to Pepco’s self-insured retention. Further, Pepco’s contracts with its vendors require the vendors to indemnify Pepco for various acts and activities that may give rise to claims against Pepco. Loss contingency liabilities for both asserted and unasserted claims are recognized if it is probable that a loss will result from such a claim and if the amounts of the losses can be reasonably estimated. Although the outcome of the claims and proceedings cannot be predicted with any certainty, management believes that there are no existing claims or proceedings that are likely to have a material adverse effect on Pepco’s financial condition, results of operations or cash flows. At December 31, 2015, Pepco had recorded estimated loss contingency liabilities for general litigation totaling approximately $4 million. Environmental Matters Pepco is subject to regulation by various federal, regional, state and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal and limitations on land use. Although penalties assessed for violations of environmental laws and regulations are not recoverable from customers of Pepco, environmental clean-up costs incurred by Pepco generally are included in its cost of service for ratemaking purposes. The total accrued liabilities for the environmental contingencies of Pepco described below at December 31, 2015 are summarized as follows: Transmission Distribution Legacy Total (millions of dollars) Balance as of January 1 $ 16 $ 3 $ 19 Accruals 4 3 7 Payments (2 ) — (2 ) Balance as of December 31 18 6 24 Less amounts in Other Current Liabilities 2 — 2 Amounts in Other Deferred Credits $ 16 $ 6 $ 22 Peck Iron and Metal Site The U.S. Environmental Protection Agency (EPA) informed Pepco in a May 2009 letter that Pepco may be a potentially responsible party (PRP) under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA) with respect to the cleanup of the Peck Iron and Metal site in Portsmouth, Virginia, and for costs EPA has incurred in cleaning up the site. The EPA letter states that Peck Iron and Metal purchased, processed, stored and shipped metal scrap from military bases, governmental agencies and businesses and that the Peck Iron and Metal scrap operations resulted in the improper storage and disposal of hazardous substances. EPA bases its allegation that Pepco arranged for disposal or treatment of hazardous substances sent to the site on information provided by former Peck Iron and Metal personnel, who informed EPA that Pepco was a customer at the site. Pepco has advised EPA by letter that its records show no evidence of any sale of scrap metal by Pepco to the site. Even if EPA has such records and such sales did occur, Pepco believes that any such scrap metal sales may be entitled to the recyclable material exemption from CERCLA liability. In September 2011, EPA initiated a remedial investigation/feasibility study (RI/FS) for the site using federal funds. Pepco cannot at this time estimate an amount or range of reasonably possible loss associated with this RI/FS, any remediation activities to be performed at the site or any other costs that EPA might seek to impose on Pepco. Benning Road Site Contamination of Lower Anacostia River In September 2010, PHI received a letter from EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site was formerly the location of a Pepco Energy Services electric generating facility. That generating facility was deactivated in June 2012 and plant structure demolition was completed in July 2015. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. The principal contaminants allegedly of concern are polychlorinated biphenyls and polycyclic aromatic hydrocarbons. In December 2011, the U.S. District Court for the District of Columbia approved a consent decree entered into by Pepco and Pepco Energy Services with the District of Columbia Department of Energy and Environment (DOEE) (formerly the District of Columbia Department of the Environment), which requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10 to 15 acre portion of the adjacent Anacostia River. The RI/FS will form the basis for the remedial actions for the Benning Road site and for the Anacostia River sediment associated with the site. The consent decree does not obligate Pepco or Pepco Energy Services to pay for or perform any remediation work, but it is anticipated that DOEE will look to Pepco and Pepco Energy Services to assume responsibility for cleanup of any conditions in the river that are determined to be attributable to past activities at the Benning Road site. The initial remedial investigation field work began in January 2013 and was completed in December 2014. In addition, in conjunction with the power plant demolition activities, Pepco and Pepco Energy Services collected soil samples adjacent to and beneath the concrete basins for the dismantled cooling towers for the generating facility. This sampling showed localized areas of soil contamination associated with the cooling tower basins, and, beginning in the first quarter of 2016, Pepco and Pepco Energy Services expect to implement a plan approved by DOEE to remove contaminated soil in conjunction with the demolition and removal of the concrete basins. On April 30, 2015, Pepco and Pepco Energy Services submitted a draft Remedial Investigation (RI) Report to DOEE. After review, DOEE determined that additional field investigation and data analysis is required to complete the RI process (much of which is beyond the scope of the original DOEE-approved RI work plan). In the meantime, Pepco and Pepco Energy Services will revise the draft RI Report as appropriate to address DOEE’s comments and DOEE will make the draft RI available for public review during the first quarter of 2016. The additional field investigation and data analysis will proceed later in 2016 according to a schedule to be developed by Pepco and Pepco Energy Services and approved by DOEE. Once the additional RI work has been completed, Pepco and Pepco Energy Services will issue a draft “final” RI report for review and comment by DOEE and the public. Pepco and Pepco Energy Services will then proceed with a feasibility study (FS) to evaluate possible remedial alternatives. This effort also may include a treatability study to evaluate the effectiveness of potential remedial options. Once the FS has been completed, Pepco and Pepco Energy Services will prepare and submit a draft FS Report for review and comment by DOEE and the public. Thereafter, Pepco and Pepco Energy Services will revise the draft FS Report as appropriate to address comments received and will submit a final FS Report to DOEE. Upon DOEE’s approval of the final RI and FS Reports, Pepco and Pepco Energy Services will have satisfied their obligations under the consent decree. At that point, DOEE will prepare a Proposed Plan regarding further response actions based on the results of the RI/FS. After considering public comment on the Proposed Plan, DOEE will issue a Record of Decision identifying any further response actions determined to be necessary. DOEE, Pepco and Pepco Energy Services must submit their next joint status report to the court regarding progress on the RI/FS by May 24, 2016. Pepco and Pepco Energy Services have determined that a loss associated with this matter for Pepco and Pepco Energy Services is probable and have estimated that the costs of remediation are in the range of approximately $8 million to $12 million. The remediation costs accrued for this matter are included in the table above in the columns entitled “Transmission and Distribution” and “Legacy Generation – Regulated.” NPDES Permit Limit Exceedances Pepco holds a National Pollutant Discharge Elimination System (NPDES) permit issued by EPA with a July 19, 2009 effective date, which authorizes discharges from the Benning Road site, including the Pepco Energy Services generating facility previously located on the site that was deactivated in 2012 and has been demolished. The 2009 permit for the first time imposed numerical limits on the allowable concentration of certain metals in storm water discharged from the site into the Anacostia River as determined by EPA to be necessary to meet the applicable District of Columbia surface water quality standards. The permit contemplated that Pepco would meet these limits over time through the use of best management practices (BMPs). As of December 2012, Pepco completed the implementation of the first two phases of BMPs identified in a plan approved by EPA (consisting principally of installing metal absorbing filters to capture contaminants at storm water inlets, removing stored equipment from areas exposed to the weather, covering and painting exposed metal pipes, and covering and cleaning dumpsters). These measures were effective in reducing metal concentrations in storm water discharges, but were not sufficient to meet all of the numerical limits for metals. Most of the quarterly monitoring results since the issuance of the permit have shown exceedances of the limits for copper and zinc, as well as occasional exceedances for iron and lead. The NPDES permit was due to expire on June 19, 2014. Pepco submitted a permit renewal application on December 17, 2013. In November 2014, EPA advised Pepco that it will not renew the permit until the Benning Road site has come into compliance with the existing permit limits. The current permit remains in effect pending EPA’s action on the renewal application. In December 2014, Pepco submitted a plan to EPA to implement the third phase of BMPs recommended in the original permit compliance plan with the objective of achieving full compliance with the permit limits for metals by the end of 2015 and Pepco immediately began to implement the additional BMPs in accordance with the plan. On September 1, 2015, Pepco submitted a report to EPA on the status of implementation of the third phase of BMPs. As of that date, Pepco had fully implemented most of the elements of the Phase 3 plan, including installation of upgraded storm water inlet controls (filters and booms), enhanced inspection and maintenance of inlets, removal of materials and equipment from exposure to storm water, and removal of accumulated sediments from the underground storm drains. The sampling results from the third quarter of 2015 showed compliance with all of the permit limits. The sampling results from the fourth quarter of 2015 showed compliance with all but a single permit limit for metals; the concentration of copper was below the daily maximum limit but exceeded the monthly average limit. As confirmed by this latest sampling, because the permit limits are low and site conditions are subject to variation, Pepco has concluded that some form of storm water treatment prior to discharge will be necessary to ensure ongoing compliance with all permit limits and has begun the process of evaluating treatment options. The nature and scope of the necessary treatment system, and the amount of the associated capital expenditures, will not be known until Pepco has completed the evaluation and design process. Pepco has been engaged in discussions with representatives from EPA and the DOJ regarding permit compliance. On October 30, 2015, EPA filed a Clean Water Act civil enforcement action against Pepco in federal district court. Pepco expects that this enforcement action will be resolved through a consent decree that will (i) establish further requirements to achieve compliance with the permit limits, including the design and installation of an appropriate storm water treatment system as noted above, and (ii) include civil penalties for past noncompliance. The amount of such penalties is not known or estimable at this time and Pepco does not expect the amount of such penalties to have a material adverse effect on PHI’s consolidated financial condition, results of operations or cash flows. Pepco and EPA are currently in discussions regarding the terms of the contemplated consent decree, and it is anticipated that the parties will finalize the consent decree during the first half of 2016. In response to a joint motion by the parties, the court has extended the deadline for Pepco to answer the complaint to May 16, 2016, to give the parties time to work towards agreement on the terms of a consent decree. The parties contemplate seeking a further extension if necessary to complete their negotiations. Once executed by the parties, the consent decree will be filed with the court for review and approval following a period for public comment. Potomac River Mineral Oil Release In January 2011, a coupling failure on a transformer cooler pipe resulted in a release of non-toxic mineral oil at Pepco’s Potomac River substation in Alexandria, Virginia. An overflow of an underground secondary containment reservoir resulted in approximately 4,500 gallons of mineral oil flowing into the Potomac River. In March 2014, Pepco and DOEE entered into a consent decree to resolve a threatened DOEE enforcement action, the terms of which include a combination of a civil penalty and a Supplemental Environmental Project (SEP) with a total cost to Pepco of $875,000. The consent decree was approved and entered by the District of Columbia Superior Court on April 4, 2014. Pepco has paid the $250,000 civil penalty imposed under the consent decree and, pursuant to the consent decree, has made a one-time donation in the amount of $25,000 to the Northeast Environmental Enforcement Training Fund, Inc., a non-profit organization that funds scholarships for environmental enforcement training. The consent decree confirmed that no further actions are required by Pepco to investigate, assess or remediate impacts to the river from the mineral oil release. To implement the SEP, Pepco has entered into an agreement with Living Classrooms Foundation, Inc., a non-profit educational organization, pursuant to which Pepco will provide $600,000 to fund the design, installation and operation of a trash collection system at a storm water outfall that drains to the Anacostia River. DOEE approved the design for the trash collection system and efforts to secure necessary permits are in progress. Pepco expects that this system will be constructed and placed into operation by the end of 2016, which will satisfy Pepco’s obligations under the consent decree. On September 11, 2015, Pepco and DOEE filed a joint report with the D.C. Superior Court on the status of the trash cage project and other elements of the consent decree. The court accepted that report and scheduled the next status hearing in this matter for September 23, 2016. The consent decree did not resolve potential claims under federal law for natural resource damages resulting from the mineral oil release. Pepco has engaged in separate discussions with DOEE and the federal resource trustees regarding the settlement of a possible natural resource damages claim under federal law. In July 2013, Pepco submitted a natural resource damage assessment to DOEE and the federal trustees that proposed monetary compensation for such damages in the range of $106,000 to $161,000. By letter dated September 16, 2015, the U.S. Department of Interior, on behalf of the trustees, made a confidential counter-proposal for settlement of the natural resource damage claim. Pepco has engaged in subsequent discussions with the trustees and believes that the parties are close to reaching an agreement to settle the claims. Based on the discussions to date, PHI and Pepco do not believe that the resolution of the natural resource damages claim will have a material adverse effect on their respective financial condition, results of operations or cash flows. As a result of the mineral oil release, Pepco implemented certain interim operational changes to the secondary containment systems at the facility, which involve pumping accumulated storm water to an above-ground holding tank for off-site disposal. Pepco is continuing to use the above-ground holding tank to manage storm water from the secondary containment system while it evaluates other technical and regulatory options. The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.” Metal Bank Site In the first quarter of 2013, the National Oceanic and Atmospheric Administration (NOAA) contacted Pepco on behalf of itself and other federal and state trustees to request that Pepco execute a tolling agreement to facilitate settlement negotiations concerning natural resource damages allegedly caused by releases of hazardous substances, including polychlorinated biphenyls, at the Metal Bank Cottman Avenue Superfund Site located in Philadelphia, Pennsylvania. Pepco executed a tolling agreement, which has been extended to March 15, 2016, and will continue settlement discussions with the NOAA, the trustees and other PRPs. The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.” Brandywine Fly Ash Disposal Site In February 2013, Pepco received a letter from the Maryland Department of the Environment (MDE) requesting that Pepco investigate the extent of waste on a Pepco right-of-way that traverses the Brandywine fly ash disposal site in Brandywine, Prince George’s County, Maryland, owned by NRG Energy, Inc. (as successor to GenOn MD Ash Management, LLC) (NRG). In July 2013, while reserving its rights and related defenses under a 2000 agreement covering the sale of this site, Pepco indicated its willingness to investigate the extent of, and propose an appropriate closure plan to address, ash on the right-of-way. Pepco submitted a schedule for development of a closure plan to MDE on September 30, 2013 and, by letter dated October 18, 2013, MDE approved the schedule. Pepco has determined that a loss associated with this matter for Pepco is probable and has estimated that the costs for implementation of a closure plan and cap on the site are in the range of approximately $3 million to $6 million. Pepco believes that the costs incurred in this matter will be recoverable from NRG under the 2000 sale agreement. The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.” Rock Creek Mineral Oil Release In late August 2015, a Pepco underground transmission line in the District of Columbia suffered a breach, resulting in the release of non-toxic mineral oil surrounding the transmission line into the surrounding soil, and a small amount also reached Rock Creek through a storm drain. Pepco notified regulatory authorities, and Pepco and its spill response contractors placed booms in Rock Creek, blocked the storm drain to prevent the release of mineral oil into the creek and commenced remediation of soil around the transmission line and the Rock Creek shoreline. Pepco estimates that approximately 6,100 gallons of mineral oil were released and that its remediation efforts recovered approximately 80 percent of the amount released. Pepco’s remediation efforts are ongoing under the direction of the DOEE and in collaboration with the National Park Service, the Smithsonian Institution/National Zoo and EPA. Pepco’s investigation presently indicates that the damage to Pepco’s facilities occurred prior to the release of mineral oil when third-party excavators struck the Pepco underground transmission line while installing cable for another utility. To the extent recovery is available against any party who contributed to this loss, Pepco will pursue such action. Pepco continues to investigate the cause of the incident, the parties involved, and legal responsibility under District of Columbia law, but does not believe that the remediation costs to resolve this matter will have a material adverse effect on its financial condition, results of operations or cash flows. Contractual Obligations Power Purchase Contracts As of December 31, 2015, Pepco had no contractual obligations under non-derivative power purchase contracts. Lease Commitments Rental expense for operating leases was $7 million, $8 million and $7 million for the years ended December 31, 2015, 2014 and 2013, respectively. Total future minimum operating lease payments for Pepco as of December 31, 2015 are $7 million in 2016, $6 million in 2017, $5 million in 2018, $4 million in 2019, $3 million in 2020 and $7 million thereafter. |
Delmarva Power & Light Co/De [Member] | |
Commitments and Contingencies | (14) COMMITMENTS AND CONTINGENCIES General Litigation From time to time, DPL is named as a defendant in litigation, usually relating to general liability or auto liability claims that resulted in personal injury or property damage to third parties. DPL is self-insured against such claims up to a certain self-insured retention amount and maintains insurance coverage against such claims at higher levels, to the extent deemed prudent by management. In addition, DPL’s contracts with its vendors generally require the vendors to name DPL as an additional insured for the amount at least equal to DPL’s self-insured retention. Further, DPL’s contracts with its vendors require the vendors to indemnify DPL for various acts and activities that may give rise to claims against DPL. Loss contingency liabilities for both asserted and unasserted claims are recognized if it is probable that a loss will result from such a claim and if the amounts of the losses can be reasonably estimated. Although the outcome of the claims and proceedings cannot be predicted with any certainty, management believes that there are no existing claims or proceedings that are likely to have a material adverse effect on DPL’s financial condition, results of operations or cash flows. At December 31, 2015, DPL had recorded estimated loss contingency liabilities for general litigation totaling approximately $3 million. Environmental Matters DPL is subject to regulation by various federal, regional, state, and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal and limitations on land use. Although penalties assessed for violations of environmental laws and regulations are not recoverable from DPL’s customers, environmental clean-up costs incurred by DPL generally are included in its cost of service for ratemaking purposes. The total accrued liabilities for the environmental contingencies of DPL described below at December 31, 2015 are summarized as follows: Transmission Legacy Generation - Regulated Total (millions of dollars) Balance as of January 1 $ 1 $ 2 $ 3 Accruals 3 — 3 Payments (2 ) (1 ) (3 ) Balance as of December 31 2 1 3 Less amounts in Other Current Liabilities 1 1 2 Amounts in Other Deferred Credits $ 1 $ — $ 1 Metal Bank Site In the first quarter of 2013, the National Oceanic and Atmospheric Administration (NOAA) contacted DPL on behalf of itself and other federal and state trustees to request that DPL execute a tolling agreement to facilitate settlement negotiations concerning natural resource damages allegedly caused by releases of hazardous substances, including polychlorinated biphenyls, at the Metal Bank Cottman Avenue Superfund Site located in Philadelphia, Pennsylvania. DPL executed a tolling agreement, which has been extended to March 15, 2016, and will continue settlement discussions with the NOAA, the trustees and other potentially responsible parties. The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.” Virginia Department of Environmental Quality Notice of Violation On February 3, 2015, the Virginia Department of Environmental Quality (VDEQ) issued a notice of violation (NOV) to DPL in connection with alleged violations of state water control laws and regulations associated with recent construction activities undertaken to replace certain transmission facilities. The NOV informed DPL of information on which VDEQ may rely to institute an administrative or judicial enforcement action, requested a meeting, and stated that DPL may be asked to enter into a consent order to formalize a plan and schedule of corrective action and settle any outstanding issues regarding the matter including the assessment of civil charges. At a February 20, 2015 meeting, VDEQ confirmed that the NOV would be resolved through a consent order, which will require the payment of a penalty, but did not specify the potential penalty amount. DPL will pursue recovery of the restoration costs for this matter from the contractor responsible for the vegetation management activities that gave rise to the alleged violations. DPL has substantially completed all remediation activities related to this matter and does not believe that the potential penalty to resolve this matter will have a material adverse effect on its financial condition, results of operations or cash flows. Contractual Obligations Power Purchase Contracts As of December 31, 2015, DPL’s contractual obligations under non-derivative power purchase contracts were $64 million in 2016, $127 million in 2017 to 2018, $128 million in 2019 to 2020 and $296 million thereafter. Lease Commitments DPL leases an 11.9% interest in the Merrill Creek Reservoir. The lease is an operating lease and payments over the remaining lease term, which ends in 2032, are $75 million in the aggregate. DPL also has long-term leases for certain other facilities and equipment. Total future minimum operating lease payments for DPL, including the Merrill Creek Reservoir lease, as of December 31, 2015, are $13 million in 2016, $12 million in 2017, $16 million in 2018, $6 million in 2019, $9 million in 2020 and $118 million thereafter. Rental expense for operating leases, including the Merrill Creek Reservoir lease, was $14 million, $14 million and $13 million for the years ended December 31, 2015, 2014 and 2013, respectively. |
Atlantic City Electric Co [Member] | |
Commitments and Contingencies | (13) COMMITMENTS AND CONTINGENCIES General Litigation From time to time, ACE is named as a defendant in litigation, usually relating to general liability or auto liability claims that resulted in personal injury or property damage to third parties. ACE is self-insured against such claims up to a certain self-insured retention amount and maintains insurance coverage against such claims at higher levels, to the extent deemed prudent by management. In addition, ACE’s contracts with its vendors generally require the vendors to name ACE as an additional insured for the amount at least equal to ACE’s self-insured retention. Further, ACE’s contracts with its vendors require the vendors to indemnify ACE for various acts and activities that may give rise to claims against ACE. Loss contingency liabilities for both asserted and unasserted claims are recognized if it is probable that a loss will result from such a claim and if the amounts of the losses can be reasonably estimated. Although the outcome of the claims and proceedings cannot be predicted with any certainty, management believes that there are no existing claims or proceedings that are likely to have a material adverse effect on ACE’s financial condition, results of operations or cash flows. At December 31, 2015, ACE had recorded estimated loss contingency liabilities for general litigation totaling approximately $5 million. Environmental Matters ACE is subject to regulation by various federal, regional, state and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal and limitations on land use. Although penalties assessed for violations of environmental laws and regulations are not recoverable from customers of ACE, environmental clean-up costs incurred by ACE generally are included in its cost of service for ratemaking purposes. The total accrued liabilities for the environmental contingencies of ACE described below at December 31, 2015 are summarized as follows: Legacy Generation - (millions of dollars) Balance as of January 1 $ 1 Accruals — Payments — Balance as of December 31 1 Less amounts in Other Current Liabilities — Amounts in Other Deferred Credits $ 1 Franklin Slag Pile Site In November 2008, ACE received a general notice letter from the U.S. Environmental Protection Agency (EPA) concerning the Franklin Slag Pile site in Philadelphia, Pennsylvania, asserting that ACE is a potentially responsible party that may have liability for clean-up costs with respect to the site and for the costs of implementing an EPA-mandated remedy. EPA’s claims are based on ACE’s sale of boiler slag from the B.L. England generating facility, then owned by ACE, to MDC Industries, Inc. (MDC) during the period from June 1978 to May 1983. EPA claims that the boiler slag ACE sold to MDC contained copper and lead, which are hazardous substances under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA), and that the sales transactions may have constituted an arrangement for the disposal or treatment of hazardous substances at the site, which could be a basis for liability under CERCLA. The EPA letter also states that, as of the date of the letter, EPA’s expenditures for response measures at the site have exceeded $6 million. EPA’s feasibility study (FS) for this site conducted in 2007 identified a range of alternatives for permanent remedial measures with varying cost estimates, and the estimated cost of EPA’s preferred alternative is approximately $6 million. ACE believes that the B.L. England boiler slag sold to MDC was a valuable material with various industrial applications and, therefore, the sale was not an arrangement for the disposal or treatment of any hazardous substances as would be necessary to constitute a basis for liability under CERCLA. ACE intends to contest any claims to the contrary made by EPA. In a May 2009 decision arising under CERCLA, which did not involve ACE, the U.S. Supreme Court rejected an EPA argument that the sale of a useful product constituted an arrangement for disposal or treatment of hazardous substances. While this decision supports ACE’s position, at this time ACE cannot predict how EPA will proceed with respect to the Franklin Slag Pile site, or what portion, if any, of the Franklin Slag Pile site response costs EPA would seek to recover from ACE. Costs to resolve this matter are not expected to be material and are expensed as incurred. Contractual Obligations Power Purchase Contracts As of December 31, 2015, ACE’s contractual obligations under non-derivative power purchase contracts were $203 million in 2016, $341 million in 2017 to 2018, $344 million in 2019 to 2020 and $697 million thereafter. Lease Commitments ACE leases certain types of property and equipment for use in its operations. Rental expense for operating leases was $13 million, $12 million and $12 million for the years ended December 31, 2015, 2014 and 2013, respectively. Total future minimum operating lease payments for ACE as of December 31, 2015 are $8 million in 2016, $8 million 2017, $7 million in 2018, $6 million in 2019, $6 million in 2020 and $30 million thereafter. |
Variable Interest Entities
Variable Interest Entities | 12 Months Ended |
Dec. 31, 2015 | |
Variable Interest Entities | (17) VARIABLE INTEREST ENTITIES PHI is required to consolidate a VIE in accordance with FASB ASC 810 if PHI or a subsidiary is the primary beneficiary of the VIE. The primary beneficiary of a VIE is typically the entity with both the power to direct activities most significantly impacting economic performance of the VIE and the obligation to absorb losses or receive benefits of the VIE that could potentially be significant to the VIE. PHI performs a qualitative analysis to determine whether a variable interest provides a controlling financial interest in any of the VIEs in which PHI or its subsidiaries have an interest. Set forth below are the relationships with respect to which PHI conducted a VIE analysis as of December 31, 2015: DPL Renewable Energy Transactions DPL is subject to Renewable Energy Portfolio Standards (RPS) in the state of Delaware that require it to obtain renewable energy credits (RECs) for energy delivered to its customers. DPL’s costs associated with obtaining RECs to fulfill its RPS obligations are recoverable from its customers by law. As of December 31, 2015, DPL is a party to three land-based wind PPAs in the aggregate amount of 128 MWs, one solar PPA with a 10 MW facility, and a PPA with the Delaware Sustainable Energy Utility (DSEU) to purchase solar renewable energy credits (SRECs). Each of the facilities associated with these PPAs is operational, except for the facilities associated with the PPA with the DSEU, which are expected to be operational within one year. DPL is obligated to purchase energy and RECs in amounts generated and delivered by the wind facilities and SRECs from the solar facility and the DSEU, up to certain amounts (as set forth below) at rates that are primarily fixed under the respective agreements. PHI and DPL have concluded that while VIEs exist under these contracts, consolidation is not required under FASB ASC 810 as DPL is not the primary beneficiary. DPL has not provided financial or other support under these arrangements that it was not previously contractually required to provide during the periods presented, and DPL does not have any intention to provide such additional support. Because DPL has no equity or debt interest in these renewable energy transactions, the maximum exposure to loss relates primarily to any above-market costs incurred for power, RECs or SRECs. Due to unpredictability in the amount of MWs ultimately purchased under the agreements for purchased renewable energy, RECs and SRECs, PHI and DPL are unable to quantify the maximum exposure to loss, however, the power purchase, REC and SREC costs are recoverable from DPL’s customers through regulated rates. Wind PPAs DPL is obligated to purchase energy and RECs from one of the wind facilities through 2024 in amounts not to exceed 50 MWs, from the second wind facility through 2031 in amounts not to exceed 40 MWs, and from the third wind facility through 2031 in amounts not to exceed 38 MWs. DPL’s aggregate purchases under the three wind PPAs totaled $29 million, $31 million and $30 million for the years ended December 31, 2015, 2014 and 2013, respectively. Solar PPAs The term of the PPA with the solar facility is through 2030 and DPL is obligated to purchase SRECs in an amount up to 70 percent of the energy output at a fixed price. The DSEU may enter into 20-year contracts with solar facilities to purchase SRECs for resale to DPL. Under the PPA with the DSEU, at December 31, 2015 and 2014, DPL was obligated to purchase SRECs in amounts not to exceed 28 MWs and 19 MWs, respectively, at annually determined auction rates. DPL’s purchases under these solar PPAs totaled $6 million, $6 million and $3 million for the years ended December 31, 2015, 2014 and 2013, respectively. Fuel Cell Facilities On October 18, 2011, the DPSC approved a tariff submitted by DPL in accordance with the requirements of the RPS specific to fuel cell facilities totaling 30 MWs to be constructed by a qualified fuel cell provider. The tariff and the RPS establish that DPL acts solely as an agent to collect payments in advance from its distribution customers and remit them to the qualified fuel cell provider for each megawatt hour (MWh) of energy produced by the fuel cell facilities through 2033. The RPS provides for a reduction in DPL’s REC requirements based upon the actual energy output of the facilities. PHI and DPL have concluded that while a VIE exists as a result of this relationship, consolidation is not required under FASB ASC 810 as DPL is not the primary beneficiary. For the years ended December 31, 2015 and 2014, 227,113 and 222,948 MWhs, respectively, were produced from fuel cell facilities placed in service under the tariff. DPL billed $37 million, $36 million and $23 million to distribution customers for the years ended December 31, 2015, 2014 and 2013, respectively. ACE Power Purchase Agreements ACE is a party to three PPAs with unaffiliated NUGs totaling 459 MWs. One of the agreements ends in 2016 and the other two end in 2024. PHI and ACE have no equity or debt invested in these entities. In performing its VIE analysis, PHI has been unable to obtain sufficient information to determine whether these three entities were variable interest entities or if ACE was the primary beneficiary. As a result, PHI has applied the scope exemption from the consolidation guidance. Because ACE has no equity or debt invested in the NUGs, the maximum exposure to loss relates primarily to any above-market costs incurred for power. Due to unpredictability in the pricing for purchased energy under the PPAs, PHI and ACE are unable to quantify the maximum exposure to loss. The power purchase costs are recoverable from ACE’s customers through regulated rates. Purchase activities with the NUGs, including excess power purchases not covered by the PPAs, for the years ended December 31, 2015, 2014 and 2013, were approximately $208 million, $233 million and $221 million, respectively, of which approximately $198 million, $208 million and $206 million, respectively, consisted of power purchases under the PPAs. ACE Funding In 2001, ACE established ACE Funding solely for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of Transition Bonds. The proceeds of the sale of each series of Transition Bonds were transferred to ACE in exchange for the transfer by ACE to ACE Funding of the right to collect a non-bypassable Transition Bond Charge (representing revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees) from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on the Transition Bonds and related taxes, expenses and fees (Bondable Transition Property). The assets of ACE Funding, including the Bondable Transition Property, and the Transition Bond Charges collected from ACE’s customers, are not available to creditors of ACE. The holders of Transition Bonds have recourse only to the assets of ACE Funding. ACE owns 100 percent of the equity of ACE Funding, and PHI and ACE consolidate ACE Funding in their consolidated financial statements as ACE is the primary beneficiary of ACE Funding under the variable interest entity consolidation guidance. |
Delmarva Power & Light Co/De [Member] | |
Variable Interest Entities | (17) VARIABLE INTEREST ENTITIES DPL is required to consolidate a VIE in accordance with FASB ASC 810 if DPL is the primary beneficiary of the VIE. The primary beneficiary of a VIE is typically the entity with both the power to direct activities most significantly impacting economic performance of the VIE and the obligation to absorb losses or receive benefits of the VIE that could potentially be significant to the VIE. DPL performed a qualitative analysis to determine whether a variable interest provided a controlling financial interest in any of the VIEs in which DPL has an interest at December 31, 2015, as described below. DPL is subject to Renewable Energy Portfolio Standards (RPS) in the state of Delaware that require it to obtain renewable energy credits (RECs) for energy delivered to its customers. DPL’s costs associated with obtaining RECs to fulfill its RPS obligations are recoverable from its customers by law. As of December 31, 2015, DPL is a party to three land-based wind PPAs in the aggregate amount of 128 MWs, one solar power PPA with a 10 MW facility, and a PPA with the Delaware Sustainable Energy Utility (DSEU) to purchase solar renewable energy credits (SRECs). Each of the facilities associated with these PPAs is operational, except for the facilities associated with the PPA with the DSEU, which are expected to be operational within one year. DPL is obligated to purchase energy and RECs in amounts generated and delivered by the wind facilities and SRECs from the solar facility and the DSEU, up to certain amounts (as set forth below) at rates that are primarily fixed under the respective agreements. DPL has concluded that while VIEs exist under these contracts, consolidation is not required under FASB ASC 810 as DPL is not the primary beneficiary. DPL has not provided financial or other support under these arrangements that it was not previously contractually required to provide during the periods presented, and DPL does not have any intention to provide such additional support. Because DPL has no equity or debt interest in these renewable energy transactions, the maximum exposure to loss relates primarily to any above-market costs incurred for power, RECs or SRECs. Due to unpredictability in the amount of MWs ultimately purchased under the agreements for purchased renewable energy, RECs and SRECs, DPL is unable to quantify the maximum exposure to loss, however, the power purchase, REC and SREC costs are recoverable from DPL’s customers through regulated rates. Wind PPAs DPL is obligated to purchase energy and RECs from one of the wind facilities through 2024 in amounts not to exceed 50 MWs, from the second wind facility through 2031 in amounts not to exceed 40 MWs, and from the third wind facility through 2031 in amounts not to exceed 38 MWs. DPL’s aggregate purchases under the three wind PPAs totaled $29 million, $31 million and $30 million for the years ended December 31, 2015, 2014 and 2013, respectively. Solar PPAs The term of the PPA with the solar facility is through 2030 and DPL is obligated to purchase SRECs in an amount up to 70 percent of the energy output at a fixed price. The DSEU may enter into 20-year contracts with solar facilities to purchase SRECs for resale to DPL. Under the PPA with DSEU, at December 31, 2015 and 2014, DPL was obligated to purchase SRECs in amounts not to exceed 28 MWs and 19 MWs, respectively, at annually determined auction rates. DPL’s purchases under these solar agreements totaled $6 million, $6 million and $3 million for the years ended December 31, 2015, 2014 and 2013, respectively. Fuel Cell Facilities On October 18, 2011, the DPSC approved a tariff submitted by DPL in accordance with the requirements of the RPS specific to fuel cell facilities totaling 30 MWs to be constructed by a qualified fuel cell provider. The tariff and the RPS establish that DPL acts solely as an agent to collect payments in advance from its distribution customers and remit them to the qualified fuel cell provider for each megawatt hour (MWh) of energy produced by the fuel cell facilities through 2033. The RPS provides for a reduction in DPL’s REC requirements based upon the actual energy output of the facilities. DPL has concluded that while a VIE exists as a result of this relationship, consolidation is not required under FASB ASC 810 as DPL is not the primary beneficiary. For the years ended December 31, 2015 and 2014, 227,113 and 222,948 MWhs, respectively, were produced from fuel cell facilities placed in service under the tariff. DPL billed $37 million, $36 million and $23 million to distribution customers for the years ended December 31, 2015, 2014 and 2013, respectively. ACE Management’s Report on Internal Control Over Financial Reporting The management of Atlantic City Electric Company (ACE) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Management of ACE assessed ACE’s internal control over financial reporting as of December 31, 2015 based on criteria established in the Internal Control – Integrated Framework (2013) Report of Independent Registered Public Accounting Firm To the Shareholder and Board of Directors of Atlantic City Electric Company In our opinion, the consolidated financial statements of Atlantic City Electric Company (a wholly owned subsidiary of Pepco Holdings, Inc.) listed in the accompanying index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Atlantic City Electric Company and its subsidiary at December 31, 2015 and December 31, 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule of Atlantic City Electric Company listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. |
Atlantic City Electric Co [Member] | |
Variable Interest Entities | (16) VARIABLE INTEREST ENTITIES ACE is required to consolidate a VIE in accordance with FASB ASC 810 if ACE or a subsidiary is the primary beneficiary of the VIE. The primary beneficiary of a VIE is typically the entity with both the power to direct activities most significantly impacting economic performance of the VIE and the obligation to absorb losses or receive benefits of the VIE that could potentially be significant to the VIE. ACE performed a qualitative analysis to determine whether a variable interest provided a controlling financial interest in any of the VIE’s in which ACE has an interest at December 31, 2015, as described below. Power Purchase Agreements ACE is a party to three PPAs with unaffiliated NUGs totaling 459 megawatts. One of the agreements ends in 2016 and the other two end in 2024. ACE has no equity or debt invested in these entities. In performing its VIE analysis, ACE has been unable to obtain sufficient information to determine whether these three entities were variable interest entities or if ACE was the primary beneficiary. As a result, ACE has applied the scope exemption from the consolidation guidance. Because ACE has no equity or debt invested in the NUGs, the maximum exposure to loss relates primarily to any above-market costs incurred for power. Due to unpredictability in the pricing for purchased energy under the PPAs, ACE is unable to quantify the maximum exposure to loss. The power purchase costs are recoverable from ACE’s customers through regulated rates. Purchase activities with the NUGs, including excess power purchases not covered by the PPAs, for the years ended December 31, 2015, 2014 and 2013, were approximately $208 million, $233 million and $221 million, respectively, of which approximately $198 million, $208 million and $206 million, respectively, consisted of power purchases under the PPAs. ACE Funding In 2001, ACE established ACE Funding solely for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of Transition Bonds. The proceeds of the sale of each series of Transition Bonds were transferred to ACE in exchange for the transfer by ACE to ACE Funding of the right to collect a non-bypassable Transition Bond Charge (which is revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees) from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on the Transition Bonds and related taxes, expenses and fees (Bondable Transition Property). The assets of ACE Funding, including the Bondable Transition Property, and the Transition Bond Charges collected from ACE’s customers, are not available to creditors of ACE. The holders of Transition Bonds have recourse only to the assets of ACE Funding. ACE owns 100 percent of the equity of ACE Funding, and PHI and ACE consolidate ACE Funding in their consolidated financial statements as ACE is the primary beneficiary of ACE Funding under the variable interest entity consolidation guidance. |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Loss | 12 Months Ended |
Dec. 31, 2015 | |
Equity [Abstract] | |
Accumulated Other Comprehensive Loss | (18) ACCUMULATED OTHER COMPREHENSIVE LOSS The components of Pepco Holdings’ AOCL relating to continuing and discontinued operations are as follows. For additional information, see the consolidated statements of comprehensive income. Year Ended December 31, 2015 2014 2013 (millions of dollars) Balance as of January 1 $ (46 ) $ (34 ) $ (48 ) Treasury Lock Balance as of January 1 (9 ) (9 ) (10 ) Amount of pre-tax loss reclassified to Interest expense 1 1 1 Income tax expense — 1 — Balance as of December 31 (8 ) (9 ) (9 ) Pension and Other Postretirement Benefits Balance as of January 1 (37 ) (25 ) (32 ) Amount of amortization of net prior service cost and actuarial loss reclassified to Other operation and maintenance expense 6 5 5 Amount of net prior service cost and actuarial gain (loss) arising during the year 9 (25 ) 8 Income tax (benefit) expense 6 (8 ) 6 Balance as of December 31 (28 ) (37 ) (25 ) Commodity Derivatives Balance as of January 1 — — (6 ) Amount of net pre-tax loss reclassified to Income (loss) from discontinued operations before income tax — — 10 Income tax expense — — 4 Balance as of December 31 — — — Balance as of December 31 $ (36 ) $ (46 ) $ (34 ) |
Quarterly Financial Information
Quarterly Financial Information | 12 Months Ended |
Dec. 31, 2015 | |
Quarterly Financial Information | (19) QUARTERLY FINANCIAL INFORMATION (UNAUDITED) The quarterly data presented below reflect all adjustments necessary in the opinion of management for a fair presentation of the interim results. Quarterly data normally vary seasonally because of temperature variations and differences between summer and winter rates. The totals of the four quarterly basic and diluted earnings per common share amounts may not equal the basic and diluted earnings per common share for the year due to changes in the number of shares of common stock outstanding during the year. 2015 First Quarter Second Quarter Third Quarter Fourth Quarter Total (millions of dollars, except per share amounts) Total Operating Revenue $ 1,371 $ 1,140 $ 1,362 $ 1,150 $ 5,023 Total Operating Expenses 1,229 1,001 1,179 941 (b) 4,350 Operating Income 142 139 183 209 673 Other Expenses (59 ) (59 ) (43 )(a) (65) (226) Income from Continuing Operations Before Income Tax Expense 83 80 140 144 447 Income Tax Expense Related to Continuing Operations 30 27 49 23 (c) 129 Net Income From Continuing Operations 53 53 91 121 318 Income from Discontinued Operations, net of taxes — — — 9 (d) 9 Net Income $ 53 $ 53 $ 91 $ 130 $ 327 Basic and Diluted Earnings Per Share of Common Stock: Earnings Per Share of Common Stock from Continuing Operations $ 0.21 $ 0.21 $ 0.36 $ 0.48 $ 1.25 Earnings Per Share of Common Stock from Discontinued Operations $ — $ — $ — $ 0.03 $ 0.04 Earnings Per Share of Common Stock $ 0.21 $ 0.21 $ 0.36 $ 0.51 $ 1.29 Cash Dividends Per Share of Common Stock $ 0.27 $ 0.27 $ 0.27 $ 0.27 $ 1.08 (a) Includes $15 million ($10 million after-tax) increase in fair value of preferred stock derivative. (b) Includes gains of $46 million ($27 million after-tax) associated with the sale of Pepco non-utility land. (c) Includes income tax benefit of $47 million associated with the Global Tax Settlement and a tax charge of $7 million to correct prior period errors. (d) Includes income tax benefit of $9 million associated with the Global Tax Settlement. 2014 First Quarter Second Quarter Third Quarter Fourth Quarter Total (millions of dollars, except per share amounts) Total Operating Revenue (a) $ 1,330 $ 1,117 $ 1,313 $ 1,118 $ 4,878 Total Operating Expenses (b) 1,157 966 1,147 1,004 (c) 4,274 Operating Income 173 151 166 114 604 Other Expenses (52 ) (53 ) (53 ) (66 ) (224 ) Income from Continuing Operations Before Income Tax Expense 121 98 113 48 380 Income Tax Expense Related to Continuing Operations 46 45 34 13 138 Net Income $ 75 $ 53 $ 79 $ 35 $ 242 Basic and Diluted Earnings Per Share of Common Stock $ 0.30 $ 0.21 $ 0.31 $ 0.14 $ 0.96 Cash Dividends Per Share of Common Stock $ 0.27 $ 0.27 $ 0.27 $ 0.27 $ 1.08 (a) During the fourth quarter of 2014, ACE reversed unbilled revenue of $3 million ($2 million after-tax) to correct an error that had overstated operating revenue in the third quarter of 2014. (b) Includes pre-tax impairment losses of $53 million ($32 million after-tax) and $28 million ($16 million after-tax) in the third and fourth quarters of 2014, respectively, at Pepco Energy Services associated with its combined heat and power thermal generating facilities and operations in Atlantic City. (c) Includes a charge of $3 million ($2 million after-tax) to correct a prior period error related to the recoverability of certain regulatory assets at ACE. |
Potomac Electric Power Co [Member] | |
Quarterly Financial Information | (14) QUARTERLY FINANCIAL INFORMATION (UNAUDITED) The quarterly data presented below reflect all adjustments necessary, in the opinion of management, for a fair presentation of the interim results. Quarterly data normally vary seasonally because of temperature variations and differences between summer and winter rates. Therefore, comparisons by quarter within a year are not meaningful. 2015 First Second Third Fourth Total (millions of dollars) Total Operating Revenue $ 556 $ 518 $ 612 $ 503 $ 2,189 Total Operating Expenses 493 435 497 379 (a) 1,804 Operating Income 63 83 115 124 385 Other Expenses (25 ) (23 ) (23 ) (29 ) (100 ) Income Before Income Tax Expense 38 60 92 95 285 Income Tax Expense 12 18 32 36 (b) 98 Net Income $ 26 $ 42 $ 60 $ 59 $ 187 (a) Includes gains of $46 million ($27 million after-tax) associated with the sale of non-utility land. (b) Includes net income tax benefit of $9 million associated with the Global Tax Settlement, a tax charge of $3 million for an uncertain tax position not related to the Global Tax Settlement and a tax charge of $6 million to correct prior period errors. 2014 First Second Third Fourth Total (millions of dollars) Total Operating Revenue $ 535 $ 508 $ 587 $ 471 $ 2,101 Total Operating Expenses 469 414 462 408 1,753 Operating Income 66 94 125 63 348 Other Expenses (18 ) (20 ) (20 ) (27 ) (85 ) Income Before Income Tax Expense 48 74 105 36 263 Income Tax Expense 16 28 38 10 92 Net Income $ 32 $ 46 $ 67 $ 26 $ 171 |
Delmarva Power & Light Co/De [Member] | |
Quarterly Financial Information | (16) QUARTERLY FINANCIAL INFORMATION (UNAUDITED) The quarterly data presented below reflect all adjustments necessary, in the opinion of management, for a fair presentation of the interim results. Quarterly data normally vary seasonally because of temperature variations and differences between summer and winter rates. Therefore, comparisons by quarter within a year are not meaningful. 2015 First Second Third Quarter Fourth Total (millions of dollars) Total Operating Revenue $ 423 $ 275 $ 317 $ 303 $ 1,318 Total Operating Expenses 361 251 285 256 1,153 Operating Income 62 24 32 47 165 Other Expenses (9 ) (11 ) (8 ) (12 ) (40 ) Income Before Income Tax Expense 53 13 24 35 125 Income Tax Expense 21 5 9 14 (a) 49 Net Income $ 32 $ 8 $ 15 $ 21 $ 76 (a) Includes income tax charge of $3 million associated with the Global Tax Settlement. 2014 First Quarter Second Third Quarter Fourth Total (millions of dollars) Total Operating Revenue $ 397 $ 279 $ 309 $ 308 $ 1,293 Total Operating Expenses 326 239 264 257 1,086 Operating Income 71 40 45 51 207 Other Expenses (9 ) (8 ) (9 ) (12 ) (38 ) Income Before Income Tax Expense 62 32 36 39 169 Income Tax Expense 25 13 13 14 65 Net Income $ 37 $ 19 $ 23 $ 25 $ 104 |
Atlantic City Electric Co [Member] | |
Quarterly Financial Information | (15) QUARTERLY FINANCIAL INFORMATION (UNAUDITED) The quarterly data presented below reflect all adjustments necessary, in the opinion of management, for a fair presentation of the interim results. Quarterly data normally vary seasonally because of temperature variations and differences between summer and winter rates. Therefore, comparisons by quarter within a year are not meaningful. 2015 First Second Third Fourth Total (millions of dollars) Total Operating Revenue $ 333 $ 286 $ 387 $ 292 $ 1,298 Total Operating Expenses 313 254 349 252 1,168 Operating Income 20 32 38 40 130 Other Expenses (14 ) (15 ) (17 ) (15 ) (61 ) Income Before Income Tax Expense 6 17 21 25 69 Income Tax Expense 2 7 7 15 (a) 31 Net Income $ 4 $ 10 $ 14 $ 10 $ 38 (a) Includes income tax charge of $3 million associated with the Global Tax Settlement and a tax charge of $2 million to correct prior period errors. 2014 First Second Third Fourth Total (millions of dollars) Total Operating Revenue (a) $ 340 $ 253 $ 347 $ 273 $ 1,213 Total Operating Expenses 309 228 295 246 (b) 1,078 Operating Income 31 25 52 27 135 Other Expenses (15 ) (15 ) (15 ) (17 ) (62 ) Income Before Income Tax Expense 16 10 37 10 73 Income Tax Expense 6 4 14 4 28 Net Income $ 10 $ 6 $ 23 $ 6 $ 45 (a) During the fourth quarter of 2014, ACE reversed unbilled revenue of $3 million ($2 million after-tax) to correct an error that had overstated operating revenue in the third quarter of 2014. (b) Includes a charge of $3 million ($2 million after-tax) to correct a prior period error related to the recoverability of certain regulatory assets. |
Discontinued Operations
Discontinued Operations | 12 Months Ended |
Dec. 31, 2015 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Discontinued Operations | (20) DISCONTINUED OPERATIONS PHI’s income (loss) from discontinued operations, net of income taxes, is comprised of the following: For the Year Ended December 31, 2015 2014 2013 (millions of dollars) Cross-border energy lease investments $ 9 $ — $ (327 ) Pepco Energy Services’ retail electric and natural gas supply businesses — — 5 Income (loss) from discontinued operations, net of income taxes $ 9 $ — $ (322 ) Cross-Border Energy Lease Investments Between 1994 and 2002, PCI entered into cross-border energy lease investments consisting of hydroelectric generation facilities, coal-fired electric generation facilities and natural gas distribution networks located outside of the United States. Each of these lease investments was structured as a sale and leaseback transaction commonly referred to as a SILO transaction. During the second and third quarters of 2013, PHI terminated early all of its interests in the remaining lease investments. PHI received aggregate net cash proceeds from these early terminations of $873 million (net of aggregate termination payments of $2.0 billion used to retire the non-recourse debt associated with the terminated leases) and recorded an aggregate pre-tax loss, including transaction costs, of approximately $3 million ($2 million after-tax), representing the excess of the carrying value of the terminated leases over the net cash proceeds received. As a result, PHI has reported the results of operations of the cross-border energy lease investments as discontinued operations in all periods presented in the accompanying consolidated statements of income (loss). Operating Results The operating results for the cross-border energy lease investments are as follows: For the Year Ended December 31, 2015 2014 2013 (millions of dollars) Operating revenue from PHI’s cross-border energy lease investments $ — $ — $ 7 Non-cash charge to reduce carrying value of PHI’s cross-border energy lease investments — — (373 ) Total operating revenue $ — $ — $ (366 ) Income (loss) from operations of discontinued operations, net of income taxes (a) $ 9 $ — $ (325 ) Net losses associated with the early termination of the cross-border energy lease investments, net of income taxes — — (2 ) Income (loss) from discontinued operations, net of income taxes $ 9 $ — $ (327 ) (a) Includes income tax benefit of approximately $9 million and $44 million for the years ended December 31, 2015 and 2013, respectively. On November 18, 2015, PHI entered into the Global Tax Settlement, as described in Note (11), “Income Taxes.” As a result of the Global Tax Settlement, PHI recorded in the fourth quarter of 2015 a tax benefit of $9 million associated with the cross-border energy lease investments. Substantially all of the tax benefit recorded represents uncertain tax positions that were settled in favor of PHI in the Global Tax Settlement. On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States • A non-cash pre-tax charge of $373 million ($313 million after-tax) to reduce the carrying value of these cross-border energy lease investments under FASB guidance on leases (ASC 840). This pre-tax charge was originally recorded in the consolidated statements of income (loss) as a reduction in operating revenue and is now reflected in income (loss) from discontinued operations, net of income taxes. • A non-cash charge of $16 million after-tax to reflect the anticipated additional net interest expense under FASB guidance for income taxes (ASC 740) related to estimated federal and state income tax obligations for the period over which the tax benefits may be disallowed. This after-tax charge was originally recorded in the consolidated statements of income (loss) as an increase in income tax expense and is now reflected in income (loss) from discontinued operations, net of income taxes. The after-tax interest charge for PHI on a consolidated basis was $70 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in the recognition of a $12 million interest benefit for the Power Delivery segment, and interest expense of $16 million for PCI and $66 million for Corporate and Other, respectively. PHI had also previously made certain business assumptions regarding foreign investment opportunities available at the end of the full lease terms. In view of the change in PHI’s tax position with respect to the tax benefits associated with the cross-border energy lease investments and PHI’s resulting decision to pursue the early termination of these investments, management concluded in the first quarter of 2013 that these business assumptions were no longer supportable and the tax effects of this conclusion were reflected in the after-tax charge of $313 million described above. PHI accrued no penalties associated with its re-assessment of the likely outcome of tax positions associated with the cross-border energy lease investments. No penalties were incurred by PHI in connection with the Global Tax Settlement. For additional information concerning these cross-border energy lease investments, see Note (16), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease Investments.” Retail Electric and Natural Gas Supply Businesses of Pepco Energy Services On March 21, 2013, Pepco Energy Services entered into an agreement whereby a third party assumed all the rights and obligations of the remaining natural gas supply customer contracts, and the associated supply obligations, inventory and derivative contracts. The transaction was completed on April 1, 2013. In addition, in the second quarter of 2013, Pepco Energy Services completed the wind-down of its retail electric supply business by terminating its remaining customer supply and wholesale purchase obligations beyond June 30, 2013. As a result, PHI has reported the results of operations of Pepco Energy Services’ retail electric and natural gas supply businesses as discontinued operations in all periods presented in the accompanying consolidated statements of income (loss). Operating Results The operating results for the retail electric and natural gas supply businesses of Pepco Energy Services are as follows: For the Year Ended December 31, 2015 2014 2013 (millions of dollars) Operating revenue $ — $ — $ 84 Income from operations of discontinued operations, net of income taxes $ — $ — $ 4 Net gains associated with accelerated disposition of retail electric and natural gas contracts, net of income taxes — — 1 Income from discontinued operations, net of income taxes (a) $ — $ — $ 5 (a) Includes income tax expense of approximately $3 million for the year ended December 31, 2013. Derivative Instruments and Hedging Activities Derivatives were used by the retail electric and natural gas supply businesses of Pepco Energy Services to hedge commodity price risk. There were no outstanding forward contracts or derivative positions for Pepco Energy Services as of December 31, 2015, 2014 and 2013. Derivatives Designated as Hedging Instruments At December 31, 2012, the cumulative net pre-tax loss related to effective cash flow hedges of the retail electric and natural gas supply businesses of Pepco Energy Services included in AOCL was $10 million ($6 million after-tax). With the assumption by a third party, on April 1, 2013, of all the rights and obligations of the derivative contracts associated with the retail natural gas supply business, PHI determined that the hedged forecasted purchases of supply for retail natural gas customers were probable not to occur. Accordingly, during the first quarter of 2013, PHI recognized $4 million of pre-tax unrealized derivative losses ($2 million after-tax) that were previously included in AOCL as cash flow hedges. The remaining pre-tax loss of $6 million included in AOCL was reclassified into income on completion of the wind-down of the retail electric business in the second quarter of 2013. Other Derivative Activity The retail electric and natural gas supply businesses of Pepco Energy Services held certain derivatives that were not in hedge accounting relationships and were not designated as normal purchases or normal sales. These derivatives were recorded at fair value on the balance sheet with the gain or loss for changes in fair value recorded through Income (loss) from discontinued operations, net of income taxes. For the years ended December 31, 2015, 2014, and 2013, the amount of the derivative gain (loss) for the retail electric and natural gas supply businesses of Pepco Energy Services recognized in Income (loss) from discontinued operations, net of income taxes is provided in the table below: For the Year Ended December 31, 2015 2014 2013 (millions of dollars) Reclassification of mark-to-market to realized on settlement of contracts $ — $ — $ 10 Unrealized mark-to-market loss — — — Total net gain $ — $ — $ 10 As of December 31, 2015, 2014 and 2013, the retail electric and natural gas supply businesses of Pepco Energy Services had no outstanding commodity forward contracts or derivative positions. |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2015 | |
Potomac Electric Power Co [Member] | |
Related Party Transactions | (13) RELATED PARTY TRANSACTIONS PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries, including Pepco. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets and other cost methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to Pepco for the years ended December 31, 2015, 2014 and 2013 were approximately $240 million, $220 million and $209 million, respectively. Pepco Energy Services performs utility maintenance services and high voltage underground transmission cabling, including services that are treated as capital costs, for Pepco. Amounts charged to Pepco by Pepco Energy Services for the years ended December 31, 2015, 2014 and 2013 were approximately $26 million, $30 million and $20 million, respectively. As of December 31, 2015 and 2014, Pepco had the following balances on its balance sheets due to related parties: 2015 2014 (millions of dollars) Payable to Related Party (current) (a) PHI Service Company $ (25 ) $ (27 ) Pepco Energy Services (b) (4 ) (2 ) Other (1 ) (1 ) Total $ (30 ) $ (30 ) (a) Included in Accounts payable due to associated companies. (b) Pepco bills customers on behalf of Pepco Energy Services where Pepco Energy Services has performed work for certain government agencies under a General Services Administration area-wide agreement. Amount also includes charges for utility work performed by Pepco Energy Services on behalf of Pepco. |
Delmarva Power & Light Co/De [Member] | |
Related Party Transactions | (15) RELATED PARTY TRANSACTIONS PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries, including DPL. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets and other cost methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to DPL for the years ended December 31, 2015, 2014 and 2013 were $179 million, $163 million and $154 million, respectively. Pepco Energy Services, Inc. and its subsidiaries (Pepco Energy Services) performs high voltage underground transmission cabling, including services that are treated as capital costs, for DPL. Amounts charged to DPL by Pepco Energy Services for the years ended December 31, 2015, 2014 and 2013 were approximately $3 million, zero and zero, respectively. In addition to the PHI Service Company charges described above, DPL’s financial statements include the following related party transactions in its statements of income: For the Year Ended December 31, 2015 2014 2013 (millions of dollars) Intercompany lease transactions (a) $ 4 $ 5 $ 4 (a) Included in Electric revenue. As of December 31, 2015 and 2014, DPL had the following balances on its balance sheets due to related parties: 2015 2014 (millions of dollars) Payable to Related Party (current) (a) PHI Service Company $ (19 ) $ (18 ) Other (1 ) 1 Total $ (20 ) $ (17 ) (a) Included in Accounts payable due to associated companies. |
Atlantic City Electric Co [Member] | |
Related Party Transactions | (14) RELATED PARTY TRANSACTIONS PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries, including ACE. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets and other cost methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to ACE for the years ended December 31, 2015, 2014 and 2013 were $143 million, $124 million and $115 million, respectively. In addition to the PHI Service Company charges described above, ACE’s consolidated financial statements include the following related party transactions in its consolidated statements of income: For the Year Ended December 31, 2015 2014 2013 (millions of dollars) Meter reading services provided by Millennium Account Services LLC (an ACE affiliate) (a) $ (4 ) $ (4 ) $ (4 ) Intercompany lease transactions (a) (1 ) (1 ) (1 ) Intercompany use revenue (b) 1 2 3 (a) Included in Other operation and maintenance expense. (b) Included in Operating revenue. As of December 31, 2015 and 2014, ACE had the following balances on its consolidated balance sheets due to related parties: 2015 2014 (millions of dollars) Payable to Related Party (current) (a) PHI Service Company $ (15 ) $ (14 ) Other (1 ) (1 ) Total $ (16 ) $ (15 ) (a) Included in Accounts payable due to associated companies. |
Schedule I
Schedule I | 12 Months Ended |
Dec. 31, 2015 | |
Condensed Financial Information of Parent Company Only Disclosure [Abstract] | |
Schedule I | Schedule I, Condensed Financial Information of Parent Company is submitted below. PEPCO HOLDINGS, INC. (Parent Company) STATEMENTS OF INCOME (LOSS) For the Year Ended December 31, 2015 2014 2013 (millions of dollars, except share data) Operating Revenue $ — $ — $ — Operating Expenses Other operation and maintenance 20 31 1 Total operating expenses 20 31 1 Operating Loss (20 ) (31 ) (1 ) Other Income (Expenses) Interest expense (47 ) (43 ) (42 ) Income from equity investments 312 291 204 Other income 15 — — Total other income 280 248 162 Income from Continuing Operations Before Income Tax 260 217 161 Income Tax (Benefit) Expense Related to Continuing Operations (58 ) (25 ) 51 Net Income from Continuing Operations 318 242 110 Income (Loss) from Discontinued Operations, net of Income Taxes 9 — (322 ) Net Income (Loss) $ 327 $ 242 $ (212 ) Comprehensive Income (Loss) $ 337 $ 230 $ (198 ) Earnings Per Share Basic earnings per share of common stock from Continuing Operations $ 1.25 $ 0.96 $ 0.45 Basic earnings (loss) per share of common stock from Discontinued Operations 0.04 — (1.31 ) Basic earnings (loss) per share of common stock $ 1.29 $ 0.96 $ (0.86 ) Diluted earnings per share of common stock from Continuing Operations $ 1.25 $ 0.96 $ 0.45 Diluted earnings (loss) per share of common stock from Discontinued Operations 0.04 — (1.31 ) Diluted earnings (loss) per share of common stock $ 1.29 $ 0.96 $ (0.86 ) The accompanying Notes are an integral part of these Financial Statements. PEPCO HOLDINGS, INC. (Parent Company) BALANCE SHEETS As of December 31, 2015 2014 (millions of dollars, except share data) ASSETS CURRENT ASSETS Cash and cash equivalents $ — $ 65 Prepayments of income taxes 171 152 Accounts receivable and other 18 9 Total Current Assets 189 226 INVESTMENTS AND OTHER ASSETS Goodwill 1,398 1,398 Investment in consolidated companies 4,636 4,256 Other 127 82 Total Investments and Other Assets 6,161 5,736 TOTAL ASSETS $ 6,350 $ 5,962 LIABILITIES AND EQUITY CURRENT LIABILITIES Short-term debt $ 784 $ 287 Current portion of long-term debt 190 250 Interest and taxes accrued 10 9 Accounts payable due to associated companies 8 13 Total Current Liabilities 992 559 DEFERRED CREDITS Notes payable due to subsidiary companies 498 494 Liabilities and accrued interest related to uncertain tax positions — 4 Total Deferred Credits 498 498 LONG-TERM DEBT 264 454 COMMITMENTS AND CONTINGENCIES (NOTE 4) PREFERRED STOCK Series A preferred stock, $.01 par value – 18,000 shares authorized, 18,000 and 12,600 shares outstanding, respectively 183 129 EQUITY Common stock, $.01 par value – 400,000,000 shares authorized, 254,289,261 and 252,728,684 shares outstanding, respectively 3 3 Premium on stock and other capital contributions 3,829 3,800 Accumulated other comprehensive loss (36 ) (46 ) Retained earnings 617 565 Total Equity 4,413 4,322 TOTAL LIABILITIES AND EQUITY $ 6,350 $ 5,962 The accompanying Notes are an integral part of these Financial Statements. PEPCO HOLDINGS, INC. (Parent Company) STATEMENTS OF CASH FLOWS For the Year Ended December 31, 2015 2014 2013 (millions of dollars) OPERATING ACTIVITIES Net income (loss) $ 327 $ 242 $ (212 ) (Income) loss from discontinued operations, net of income taxes (9 ) — 322 Adjustments to reconcile net income to net cash from operating activities: Distributions from related parties less than earnings (74 ) (149 ) (127 ) Deferred income taxes (33 ) (5 ) (7 ) Increase in fair value of preferred stock derivative (15 ) — — Other 13 18 — Changes in: Prepaid and other 6 13 2 Accounts payable (1 ) 1 6 Interest and taxes (23 ) — (141 ) Other assets and liabilities (22 ) 1 3 Net Cash From (Used By) Operating Activities 169 121 (154 ) FINANCING ACTIVITIES Dividends paid on common stock (275 ) (272 ) (270 ) Common stock issued for the Direct Stock Purchase and Dividend Reinvestment Plan and employee-related compensation 18 34 50 Issuances of common stock — — 324 Issuances of Series A preferred stock 54 126 — Capital contributions to subsidiaries, net (282 ) (210 ) (250 ) Increase in notes payable due to associated companies 4 3 491 Reacquisitions of long-term debt (250 ) — — Issuances (repayments) of short-term debt, net 197 263 (240 ) Borrowings under term loans 300 — 250 Repayments of term loans — — (450 ) Costs of issuances — — (13 ) Net Cash Used By Financing Activities (234 ) (56 ) (108 ) Net (Decrease) Increase In Cash and Cash Equivalents (65 ) 65 (262 ) Cash and Cash Equivalents at Beginning of Year 65 — 262 CASH AND CASH EQUIVALENTS AT END OF YEAR $ — $ 65 $ — The accompanying Notes are an integral part of these Financial Statements. NOTES TO FINANCIAL INFORMATION (1) BASIS OF PRESENTATION Pepco Holdings, Inc. (Pepco Holdings or PHI) is a holding company and conducts substantially all of its business operations through its subsidiaries. These condensed financial statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These statements should be read in conjunction with the consolidated financial statements and notes thereto of Pepco Holdings included in Part II, Item 8 of this Form 10-K. Pepco Holdings owns 100% of the common stock of all its significant subsidiaries. (2) NEWLY ADOPTED ACCOUNTING STANDARDS Presentation of Debt Issuance Costs (Accounting Standards Codification (ASC) 835) In April 2015, the Financial Accounting Standards Board issued new guidance for the presentation of debt issuance costs on the balance sheet. Debt issuance costs are currently required to be presented on the balance sheet as assets. However, under the new requirements, these debt issuance costs will be offset against the debt to which the costs relate. The new requirements are effective for PHI beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented; however, early adoption is permitted. PHI has elected to early adopt the new guidance in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in PHI’s balance sheet as of December 31, 2014. December 31, 2014 Reclassification December 31, 2014 (millions of dollars) Other (within investments and other assets) $ 84 $ (2 ) $ 82 Long-term debt 456 (2 ) 454 (3) DEBT For information concerning Pepco Holdings’ long-term debt obligations, see Note (10), “Debt,” to the consolidated financial statements of Pepco Holdings. (4) COMMITMENTS AND CONTINGENCIES For information concerning Pepco Holdings’ material contingencies and guarantees, see Note (16), “Commitments and Contingencies” to the consolidated financial statements of Pepco Holdings. Pepco Holdings guarantees the obligations of its wholly owned subsidiary, Pepco Energy Services, Inc. and its subsidiaries (Pepco Energy Services), under certain contracts in its energy savings performance contracting businesses and underground transmission and distribution construction business. At December 31, 2015, Pepco Holdings’ guarantees of Pepco Energy Services’ obligations under these contracts totaled $269 million. PHI also guarantees the obligations of Pepco Energy Services under surety bonds obtained by Pepco Energy Services for construction projects in these businesses. These guarantees totaled $177 million at December 31, 2015. In addition, Pepco Holdings guarantees certain obligations of Potomac Electric Power Company (Pepco), Delmarva Power & Light Company (DPL), and Atlantic City Electric Company (ACE) under surety bonds obtained by these subsidiaries, for construction projects and self-insured workers compensation matters. These guarantees totaled $56 million at December 31, 2015. Pepco Holdings, pursuant to an intercompany guarantee agreement with Potomac Capital Investment Corporation (PCI), guarantees certain intercompany obligations of PCI to its subsidiaries. This guarantee totaled $725 million at December 31, 2015. (5) INVESTMENT IN CONSOLIDATED COMPANIES Pepco Holdings’ majority owned subsidiaries are recorded using the equity method of accounting. A breakout of the balance in Investment in consolidated companies is as follows: 2015 2014 (millions of dollars) Conectiv, LLC (a) $ 2,198 $ 1,984 Potomac Electric Power Company 2,240 2,087 Potomac Capital Investment Corporation 40 30 Pepco Energy Services, Inc. 155 153 PHI Service Company 3 2 Total investment in consolidated companies $ 4,636 $ 4,256 (a) Conectiv LLC, is the parent company of Delmarva Power & Light Company and Atlantic City Electric Company. (6) DISCONTINUED OPERATIONS During 2015, the income from discontinued operations, net of income taxes, resulted from the Global Tax Settlement reached with the Internal Revenue Service which resolves tax matters related to PHI’s cross-border energy lease investments and is discussed further in Note (11), “Income Taxes” to the consolidated financial statements of Pepco Holdings. During 2014, there was no activity related to PHI’s discontinued operations. During 2013, PHI completed the termination of its interest in its cross-border energy lease investments and, as a result, these investments have been accounted for as discontinued operations. In December 2009, PHI announced the wind-down of the retail energy supply component of the Pepco Energy Services business which was comprised of the retail electric and natural gas supply businesses. In 2013, Pepco Energy Services completed the wind-down and, accordingly, the operations of Pepco Energy Services’ retail electric and natural gas supply businesses have been classified as discontinued operations. (7) RELATED PARTY TRANSACTIONS As of December 31, 2015 and 2014, PHI had the following balances on its balance sheets due (to) from related parties: 2015 2014 (millions of dollars) (Payable to) Receivable from Related Party (current) (a) Conectiv Communications, Inc. $ (4 ) $ (4 ) PHI Service Company (4 ) (10 ) Other — 1 Total $ (8 ) $ (13 ) Payable to Related Party (non-current) (b) Potomac Capital Investment Corporation $ (498 ) $ (494 ) Money Pool Balance (included in cash and cash equivalents) $ — $ 65 (a) Included in Accounts payable due to associated companies. (b) Included in Notes payable due to subsidiary companies. (8) DIVIDEND RESTRICTIONS PHI, on a stand-alone basis, generates no operating income of its own. Accordingly, its ability to pay dividends to its shareholders depends on dividends received from its subsidiaries. In addition to their future financial performance, the ability of PHI’s direct and indirect subsidiaries to pay dividends is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends and, in the case of ACE, the regulatory requirement that it obtain the prior approval of the New Jersey Board of Public Utilities before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%; (ii) the prior rights of holders of mortgage bonds and other long-term debt issued by the subsidiaries, and any other restrictions imposed in connection with the incurrence of liabilities; and (iii) certain provisions of ACE’s charter that impose restrictions on payment of common stock dividends for the benefit of preferred stockholders. Pepco, DPL and ACE have no shares of preferred stock outstanding at December 31, 2015. Currently, the capitalization ratio limitation to which ACE is subject and the restriction in the ACE charter do not limit ACE’s ability to pay common stock dividends. As further described in Note (10), “Debt,” to the consolidated financial statements of Pepco Holdings, PHI, Pepco, DPL and ACE have restrictions on total indebtedness in relation to total capitalization under the credit facility. PHI had approximately $617 million and $565 million of retained earnings free of restrictions at December 31, 2015 and 2014, respectively. These amounts represent the total retained earnings balances at those dates. The amount of restricted net assets for PHI’s consolidated subsidiaries at December 31, 2015 is $2,633 million. |
Schedule II
Schedule II | 12 Months Ended |
Dec. 31, 2015 | |
Schedule II | Schedule II, Valuation and Qualifying Accounts, for each registrant is submitted below. Pepco Holdings, Inc. Col. A Col. B Col. C Col. D Col. E Additions Description Balance at Charged to Charged to Deductions(b) Balance (millions of dollars) Year Ended December 31, 2015 Allowance for uncollectible accounts - customer and other accounts receivable $ 40 $ 59 $ 5 $ (48 ) $ 56 Year Ended December 31, 2014 Allowance for uncollectible accounts - customer and other accounts receivable $ 38 $ 46 $ 9 $ (53 ) $ 40 Year Ended December 31, 2013 Allowance for uncollectible accounts - customer and other accounts receivable $ 34 $ 37 $ 5 $ (38 ) $ 38 (a) Collection of accounts previously written off. (b) Uncollectible accounts written off. |
Potomac Electric Power Co [Member] | |
Schedule II | Potomac Electric Power Company Col. A Col. B Col. C Col. D Col. E Additions Description Balance at Charged to Charged to Deductions(b) Balance (millions of dollars) Year Ended December 31, 2015 Allowance for uncollectible accounts - customer and other accounts receivable $ 16 $ 20 $ 1 $ (20 ) $ 17 Year Ended December 31, 2014 Allowance for uncollectible accounts - customer and other accounts receivable $ 16 $ 17 $ 2 $ (19 ) $ 16 Year Ended December 31, 2013 Allowance for uncollectible accounts - customer and other accounts receivable $ 13 $ 15 $ 1 $ (13 ) $ 16 (a) Collection of accounts previously written off. (b) Uncollectible accounts written off. |
Delmarva Power & Light Co/De [Member] | |
Schedule II | Delmarva Power & Light Company Col. A Col. B Col. C Col. D Col. E Additions Description Balance at Charged to Charged to Deductions(b) Balance (millions of dollars) Year Ended December 31, 2015 Allowance for uncollectible accounts - customer and other accounts receivable $ 11 $ 20 $ 2 $ (16 ) $ 17 Year Ended December 31, 2014 Allowance for uncollectible accounts - customer and other accounts receivable $ 12 $ 13 $ 4 $ (18 ) $ 11 Year Ended December 31, 2013 Allowance for uncollectible accounts - customer and other accounts receivable $ 9 $ 11 $ 1 $ (9 ) $ 12 (a) Collection of accounts previously written off. (b) Uncollectible accounts written off. |
Atlantic City Electric Co [Member] | |
Schedule II | Atlantic City Electric Company Col. A Col. B Col. C Col. D Col. E Additions Description Balance at Charged to Charged to Deductions(b) Balance (millions of dollars) Year Ended December 31, 2015 Allowance for uncollectible accounts - customer and other accounts receivable $ 9 $ 18 $ 2 $ (12 ) $ 17 Year Ended December 31, 2014 Allowance for uncollectible accounts - customer and other accounts receivable $ 10 $ 12 $ 3 $ (16 ) $ 9 Year Ended December 31, 2013 Allowance for uncollectible accounts - customer and other accounts receivable $ 11 $ 11 $ 3 $ (15 ) $ 10 (a) Collection of accounts previously written off. (b) Uncollectible accounts written off. |
Significant Accounting Polici33
Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2015 | |
Consolidation Policy | Consolidation Policy The accompanying consolidated financial statements include the accounts of Pepco Holdings and its wholly owned subsidiaries. All material intercompany balances and transactions between subsidiaries have been eliminated. Pepco Holdings uses the equity method to report investments, corporate joint ventures, partnerships, and affiliated companies in which it holds an interest and can exercise significant influence over the operations and policies of the entity. Certain transmission and other facilities currently held are consolidated in proportion to PHI’s percentage interest in the facility. |
Consolidation of Variable Interest Entities | Consolidation of Variable Interest Entities PHI assesses its contractual arrangements with variable interest entities (VIEs) to determine whether it is the primary beneficiary and thereby has to consolidate the entities in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 810. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests. See Note (17), “Variable Interest Entities,” for additional information. |
Use of Estimates | Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the consolidated financial statements and accompanying notes. Although Pepco Holdings believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates. Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset and goodwill impairment calculations, fair value calculations for derivative instruments, pension and other postretirement benefit assumptions, the assessment of the adequacy of the allowance for uncollectible accounts, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, recognition of changes in network service transmission rates for prior service year costs, accrual of loss contingency liabilities for general litigation and auto and other liability claims, accrual of interest related to income taxes, the recognition of lease income and income tax benefits for investments in finance leases held in trust associated with PHI’s former cross-border energy lease investments (see Note (20), “Discontinued Operations – Cross-Border Energy Lease Investments”), and income tax provisions and reserves. Additionally, PHI is subject to legal, regulatory and other proceedings and claims that arise in the ordinary course of its business. PHI records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable. |
Revenue Recognition | Revenue Recognition Regulated Revenue Power Delivery recognizes revenue upon distribution of electricity and natural gas to its customers, including unbilled revenue for services rendered but not yet billed. PHI’s unbilled revenue was $139 million and $172 million as of December 31, 2015 and 2014, respectively, and these amounts are included in Accounts receivable. PHI’s utility subsidiaries calculate unbilled revenue using an output-based methodology. This methodology is based on the supply of electricity or natural gas intended for distribution to customers. The unbilled revenue process requires management to make assumptions and judgments about input factors such as customer sales mix, temperature and estimated line losses (estimates of electricity and natural gas expected to be lost in the process of its transmission and distribution to customers). The assumptions and judgments are inherently uncertain and susceptible to change from period to period, and if the actual results differ from the projected results, the impact could be material. Taxes related to the consumption of electricity and natural gas by the utility customers, such as fuel, energy, or other similar taxes, are components of the tariff rates charged by PHI’s utility subsidiaries and, as such, are billed to customers and recorded in Operating revenue. Accruals for the remittance of these taxes are recorded in Other taxes. Pepco Energy Services Revenue Revenue for Pepco Energy Services’ energy savings performance construction business and certain construction contracts in its underground transmission and distribution business is recognized using the percentage-of-completion method which recognizes revenue as work is completed and costs are incurred on its contracts. Under this method, Pepco Energy Services recognizes these contractual revenues based on the percentage of incurred costs relative to the estimated costs to complete a contract. Revenues from its operation and maintenance activities and measurement and verification activities in its energy savings business and certain construction contracts in its underground transmission and distribution business are recognized when earned. |
Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions | Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions Taxes included in PHI’s gross revenues were $322 million, $321 million and $346 million for the years ended December 31, 2015, 2014 and 2013, respectively. |
Accounting for Derivatives | Accounting for Derivatives PHI and its subsidiaries may use derivative instruments primarily to manage risk associated with commodity prices and interest rates. Risk management policies are determined by PHI’s Corporate Risk Management Committee (CRMC). The CRMC monitors interest rate fluctuation, commodity price fluctuation and credit risk exposure, and sets risk management policies that establish limits on unhedged risk. PHI accounts for its derivative activities in accordance with FASB guidance on derivatives and hedging. Derivatives are recorded on the consolidated balance sheets as Derivative assets or Derivative liabilities and measured at fair value. Changes in the fair value of derivatives held by DPL that do not qualify for hedge accounting or are not designated as hedges are presented on the consolidated statements of income (loss) as Fuel and purchased energy expense or Operating revenue, respectively. Changes in the fair value of derivatives held by DPL are deferred as regulatory assets or liabilities under the accounting guidance for regulated operations. The gain or loss on a derivative that qualifies as a cash flow hedge of an exposure to variable cash flows of a forecasted transaction is initially recorded in accumulated other comprehensive loss (AOCL) (a separate component of equity) to the extent that the hedge is effective and is subsequently reclassified into earnings, in the same category as the item being hedged, when the gain or loss from the forecasted transaction occurs. If it is probable that a forecasted transaction will not occur, the deferred gain or loss in AOCL is immediately reclassified to earnings. Gains or losses related to any ineffective portion of cash flow hedges are also recognized in earnings immediately. Changes in the fair value of derivatives designated as fair value hedges, as well as changes in the fair value of the hedged asset, liability or firm commitment, are recorded in the consolidated statements of income (loss). The impact of derivatives that are marked to market through current earnings, the ineffective portion of cash flow hedges, and the portion of fair value hedges that flows to current earnings are presented on a net basis in the consolidated statements of income (loss) as Operating revenue or as Fuel and purchased energy expense. When a hedging gain or loss is realized, it is presented on a net basis in the same line item as the underlying item being hedged. Unrealized derivative gains and losses are presented gross on the consolidated balance sheets except where contractual netting agreements are in place with individual counterparties. The fair value of derivatives is determined using quoted exchange prices where available. For instruments that are not traded on an exchange, pricing services and external broker quotes may also be used to determine fair value. For some custom and complex instruments, internal models use market-based information when external broker quotes are not available. For certain long-dated instruments, broker or exchange data are extrapolated, or capacity prices are forecasted, for future periods where information is limited. Models are also used to estimate volumes for certain transactions. PHI may enter into master netting arrangements to mitigate credit risk related to its derivatives. Under FASB guidance on offsetting of balance sheet accounts (ASC 210-20), amounts recognized for derivative assets and liabilities and the fair value amounts recognized for any related collateral positions executed with the same counterparty under such master netting agreements are offset. See Note (14), “Derivative Instruments and Hedging Activities,” for more information about the types of derivatives employed by PHI, the components of any unrealized and realized gains and losses and Note (15), “Fair Value Disclosures,” for the methodologies used to value them. |
Stock-Based Compensation | Stock-Based Compensation PHI recognizes compensation expense for stock-based awards, modifications or cancellations based on the grant-date fair value. Compensation expense is recognized over the requisite service period. A deferred tax asset and deferred tax benefit are also recognized concurrently with compensation expense for the tax effect of the deduction of stock options, restricted stock and restricted stock unit awards, which are deductible only upon exercise and/or vesting. Historically, PHI’s compensation awards had included both time-based restricted stock awards that vest over a three-year service period and performance-based restricted stock and restricted stock units that were earned based on performance over a three-year period. Beginning in 2011, stock-based compensation awards have been granted primarily in the form of restricted stock units. Since May 2012, the Board of Directors have been granted an annual time-based restricted stock unit award that vests over one year as part of their compensation. The compensation expense associated with these awards is calculated based on the estimated fair value of the awards at the grant date and is recognized over the service or performance period. PHI estimates the fair value of performance-based restricted stock unit awards using the Monte Carlo valuation model. These awards include performance conditions based upon PHI’s total stockholder return (TSR) versus a select group of peer companies over a three-year period. The effect of market conditions is considered in determining the awards’ fair value. This model values the specific features of employee share-based awards, including market-based performance conditions. PHI’s current policy is to issue new shares to satisfy vested awards of restricted stock units. |
Income Taxes | Income Taxes PHI and the majority of its subsidiaries file a consolidated federal income tax return. Federal income taxes are allocated among PHI and the subsidiaries included in its consolidated group pursuant to a written tax sharing agreement, which was approved by the Securities and Exchange Commission (SEC) in 2002 in connection with the establishment of PHI as a public utility holding company. Under this tax sharing agreement, PHI’s consolidated federal income tax liability is allocated based upon PHI’s and its subsidiaries’ separate taxable income or loss amounts. The consolidated financial statements include current and deferred income taxes. Current income taxes represent the amount of tax expected to be reported on PHI’s and its subsidiaries’ federal and state income tax returns. Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement basis and tax basis of existing assets and liabilities, and they are measured using presently enacted tax rates. See Note (11), “Income Taxes,” for a listing of primary deferred tax assets and liabilities. The portions of Pepco’s, DPL’s and ACE’s deferred tax liabilities applicable to their utility operations that have not been recovered from utility customers represent income taxes recoverable in the future and are included in Regulatory Assets on the consolidated balance sheets. See Note (7), “Regulatory Matters – Regulatory Assets and Regulatory Liabilities,” for additional information. PHI recognizes interest on underpayments and overpayments of income taxes, interest on uncertain tax positions and tax-related penalties in income tax expense. Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes. Investment tax credits are amortized to income over the useful lives of the related property. |
Cash and Cash Equivalents | Cash and Cash Equivalents Cash and cash equivalents include cash on hand, cash invested in money market funds and commercial paper held with original maturities of three months or less. |
Restricted Cash Equivalents | Restricted Cash Equivalents The Restricted cash equivalents included in Current assets and the Restricted cash equivalents included in Other assets consist of (i) cash held as collateral that is restricted from use for general corporate purposes and (ii) cash equivalents that are specifically segregated based on management’s intent to use such cash equivalents for a particular purpose. The classification as current or non-current conforms to the classification of the related liabilities. |
Accounts Receivable and Allowance for Uncollectible Accounts | Accounts Receivable and Allowance for Uncollectible Accounts PHI’s Accounts receivable balances primarily consist of customer accounts receivable arising from the sale of goods and services to customers within PHI’s service territories, other accounts receivable, and accrued unbilled revenue. Accrued unbilled revenue represents revenue earned in the current period but not billed to the customer until a future date (usually within one month after the receivable is recorded). PHI maintains an allowance for uncollectible accounts and changes in the allowance are recorded as an adjustment to Other operation and maintenance expense in the consolidated statements of income (loss). PHI determines the amount of the allowance based on specific identification of material amounts at risk by customer and maintains a reserve based on its historical collection experience. The adequacy of this allowance is assessed on a quarterly basis by evaluating all known factors, such as the aging of the receivables, historical collection experience, the economic and competitive environment and changes in the creditworthiness of its customers. Accounts receivable are written off in the period in which the receivable is deemed uncollectible and collection efforts have been exhausted. Recoveries of Accounts receivable previously written off are recorded when received. Although PHI believes its allowance is adequate, it cannot anticipate with any certainty the changes in the financial condition of its customers. As a result, PHI records adjustments to the allowance for uncollectible accounts in the period in which the new information that requires an adjustment to the reserve becomes known. |
Inventories | Inventories PHI utilizes the weighted average cost method of accounting for inventory items. Under this method, an average price is determined for the quantity of units acquired at each price level and is applied to the ending quantity to calculate the total ending inventory balance. Materials and supplies are recorded in Inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed. The cost of natural gas, including transportation costs, is included in Inventory when purchased and charged to Fuel and Purchased Energy expense when used. |
Goodwill | Goodwill Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired at the acquisition date. PHI tests its goodwill for impairment annually as of November 1 and whenever an event occurs or circumstances change in the interim that would more likely than not (that is, a greater than 50% chance) reduce the estimated fair value of a reporting unit below the carrying amount of its net assets. Factors that may result in an interim impairment test include, but are not limited to: a change in the identified reporting units; an adverse change in business conditions; a protracted decline in PHI’s stock price causing market capitalization to fall significantly below book value; an adverse regulatory action; or an impairment of long-lived assets in the reporting unit. PHI performed its most recent annual impairment test as of November 1, 2015, and its goodwill was not impaired as described in Note (6), “Goodwill.” |
Regulatory Assets and Regulatory Liabilities | Regulatory Assets and Regulatory Liabilities The operations of Pepco are regulated by the DCPSC and the MPSC. The operations of DPL are regulated by the DPSC and the MPSC. DPL’s interstate transportation and wholesale sale of natural gas are regulated by FERC. The operations of ACE are regulated by the NJBPU. The transmission of electricity by Pepco, DPL and ACE is regulated by FERC. The FASB guidance on regulated operations (ASC 980) applies to Power Delivery. It allows regulated entities, in appropriate circumstances, to defer the income statement impact of certain costs that are expected to be recovered in future rates through the establishment of regulatory assets and defer certain revenues that are expected to be refunded to customers through the establishment of regulatory liabilities. Management’s assessment of the probability of recovery of regulatory assets requires judgment and interpretation of laws, regulatory commission orders and other factors. If management subsequently determines, based on changes in facts or circumstances, that a regulatory asset is not probable of recovery, then the regulatory asset would be eliminated through a charge to earnings. Effective June 2007, the MPSC approved a bill stabilization adjustment (BSA) mechanism for retail customers of Pepco and DPL. Effective November 2009, the DCPSC approved a BSA for Pepco’s retail customers. For customers to whom the BSA applies, Pepco and DPL recognize distribution revenue based on an approved distribution charge per customer. From a revenue recognition standpoint, the BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during that period. Pursuant to this mechanism, Pepco and DPL recognize either (i) a positive adjustment equal to the amount by which revenue from Maryland and the District of Columbia retail distribution sales falls short of the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer, or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer (a Revenue Decoupling Adjustment). A net positive Revenue Decoupling Adjustment is recorded as a regulatory asset and a net negative Revenue Decoupling Adjustment is recorded as a regulatory liability. |
Leasing Activities | Leasing Activities Pepco Holdings’ lease transactions include plant, office space, equipment, software, vehicles and elements of power purchase agreements (PPAs). In accordance with FASB guidance on leases (ASC 840), these leases are classified as either leveraged leases, operating leases or capital leases. Leveraged Leases Income from investments in leveraged lease transactions, in which PHI was an equity participant, was accounted for using the financing method. In accordance with the financing method, investments in leased property were recorded as a receivable from the lessee to be recovered through the collection of future rentals. Income was recognized over the life of the lease at a constant rate of return on the positive net investment. Each quarter, PHI reviewed the carrying value of each lease, which included a review of the underlying financial assumptions, the timing and collectibility of cash flows, and the credit quality of the lessee. Changes to the underlying assumptions, if any, were accounted for in accordance with FASB guidance on leases and reflected in the carrying value of the lease effective for the quarter within which they occurred. Operating Leases An operating lease in which PHI or a subsidiary is the lessee generally results in a level income statement charge over the term of the lease, reflecting the rental payments required by the lease agreement. If rental payments are not made on a straight-line basis, PHI’s policy is to recognize rent expense on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed. Capital Leases For ratemaking purposes, capital leases in which PHI or a subsidiary is the lessee are treated as operating leases; therefore, in accordance with FASB guidance on regulated operations (ASC 980), the amortization of the leased asset is based on the recovery of rental payments through customer rates. Investments in equipment under capital leases are stated at cost, less accumulated depreciation. Depreciation is recorded on a straight-line basis over the equipment’s estimated useful life. Arrangements Containing a Lease PPAs are deemed to contain a lease if the arrangement conveys the right to control the use of property, plant or equipment. If so, PHI determines the appropriate lease accounting classification. |
Property, Plant and Equipment | Property, Plant and Equipment Property, plant and equipment is recorded at original cost, including labor, materials, asset retirement costs and other direct and indirect costs including capitalized interest. The carrying value of Property, plant and equipment is evaluated for impairment whenever circumstances indicate the carrying value of those assets may not be recoverable. Upon retirement, the cost of regulated property, net of salvage, is charged to Accumulated depreciation. For non-regulated property, the cost and accumulated depreciation of the property, plant and equipment retired or otherwise disposed of are removed from the related accounts and included in the determination of any gain or loss on disposition. The annual provision for depreciation on electric and natural gas property, plant and equipment is computed on a straight-line basis using composite rates by classes of depreciable property. Non-operating and other property is generally depreciated on a straight-line basis over the useful lives of the assets. The table below provides system-wide composite annual depreciation rates for the years ended December 31, 2015, 2014 and 2013. Transmission and 2015 2014 2013 2015 2014 2013 Pepco 2.3 % 2.3 % 2.2 % — — — DPL 2.6 % 2.6 % 2.6 % — — — ACE 2.6 % 2.6 % 2.8 % — — — Pepco Energy Services — — — 0.6 % 1.2 % 0.4 % In 2010, subsidiaries of PHI received awards from the U.S. Department of Energy (DOE) under the American Recovery and Reinvestment Act of 2009. Pepco was awarded $149 million from DOE to fund a portion of the costs incurred for the implementation of an advanced metering infrastructure (AMI) system (a system that collects, measures and analyzes energy usage data from advanced digital meters known as smart meters), direct load control, distribution automation and communications infrastructure in its Maryland and District of Columbia service territories. ACE was awarded $19 million from DOE to fund a portion of the costs incurred for the implementation of direct load control, distribution automation and communications infrastructure in its New Jersey service territory. PHI elected to recognize the award proceeds as a reduction in the carrying value of the assets acquired rather than grant income over the service period. |
Long-Lived Asset Impairment Evaluation | Long-Lived Asset Impairment Evaluation PHI evaluates long-lived assets to be held and used, such as generating property and equipment, and real estate, for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Examples of such events or changes include a significant decrease in the market price of a long-lived asset or a significant adverse change in the manner in which an asset is being used or its physical condition. A long-lived asset to be held and used is written down to its estimated fair value if the expected future undiscounted cash flow from the asset is less than its carrying value. For long-lived assets held for sale, an impairment loss is recognized to the extent that the asset’s carrying value exceeds its estimated fair value including costs to sell. |
Capitalized Interest and Allowance for Funds Used During Construction | Capitalized Interest and Allowance for Funds Used During Construction In accordance with FASB guidance on regulated operations (ASC 980), PHI’s utility subsidiaries may capitalize the capital costs of financing the construction of plant and equipment as allowance for funds used during construction (AFUDC). This results in the debt portion of AFUDC being recorded as a reduction of Interest expense and the equity portion of AFUDC being recorded as an increase to Other income in the accompanying consolidated statements of income (loss). Pepco Holdings recorded AFUDC for borrowed funds of $8 million, $7 million and $7 million for the years ended December 31, 2015, 2014 and 2013, respectively. Pepco Holdings recorded amounts for the equity component of AFUDC of $14 million, $13 million and $11 million for the years ended December 31, 2015, 2014 and 2013, respectively. |
Amortization of Debt Issuance and Reacquisition Costs | Amortization of Debt Issuance and Reacquisition Costs Pepco Holdings defers and amortizes debt issuance costs and long-term debt premiums and discounts over the lives of the respective debt issuances. When PHI utility subsidiaries refinance existing debt or redeem existing debt, any unamortized premiums, discounts and debt issuance costs, as well as debt redemption costs, are classified as regulatory assets and are amortized over the life of the original or new issue. |
Asset Removal Costs | Asset Removal Costs In accordance with FASB guidance on regulated operations (ASC 980), asset removal costs are recorded by PHI utility subsidiaries as Regulatory liabilities. At December 31, 2015 and 2014, $211 million and $250 million, respectively, of asset removal costs are included in Regulatory liabilities in the accompanying consolidated balance sheets. |
Pension and Postretirement Benefit Plans | Pension and Postretirement Benefit Plans PHI sponsors a non-contributory, defined benefit pension plan that covers substantially all employees of Pepco, DPL, ACE and certain employees of other PHI subsidiaries (the PHI Retirement Plan). PHI also provides supplemental retirement benefits to certain eligible executives and key employees through nonqualified retirement plans and provides certain postretirement health care and life insurance benefits for eligible retired employees. Most employees hired after January 1, 2005 will not have retiree health care coverage. Net periodic benefit cost is included in Other operation and maintenance expense, net of the portion of the net periodic benefit cost capitalized as part of the cost of labor for internal construction projects. After intercompany allocations, the three utility subsidiaries are responsible for substantially all of the total PHI net periodic benefit cost. PHI accounts for the PHI Retirement Plan, the nonqualified retirement plans, and the retirement health care and life insurance benefit plans in accordance with FASB guidance on retirement benefits (ASC 715). See Note (9), “Pension and Other Postretirement Benefits,” for additional information. |
Reclassifications | Reclassifications Certain prior period amounts have been reclassified in order to conform to the current period presentation. |
Discontinued Operations | Discontinued Operations (ASC 205) In April 2014, the FASB issued new guidance on the reporting of discontinued operations that is effective for dispositions that occur after January 1, 2015. In order for dispositions to be presented as discontinued operations, the dispositions must represent a strategic shift that will have a major effect on an entity’s operations and financial results. Adoption of this guidance during the first quarter of 2015 did not have an impact on PHI’s consolidated financial statements. |
Business Combinations | Business Combinations (ASC 805) In November 2014, the FASB issued new recognition and disclosure requirements related to pushdown accounting. The new recognition requirements grant an acquired entity (or its subsidiaries) the option to elect whether and when a new accounting and reporting basis (pushdown accounting) will be applied when an acquirer obtains control of the acquired entity. This election may be made by the acquired entity (or its subsidiaries) for future change-in-control events or for its most recent change-in-control event, and the acquired entity will be required to determine whether pushdown accounting will be applied in the reporting period in which the change-in-control event occurs or in a subsequent reporting period. The new required disclosures include information that enables financial statement users to evaluate the effects of pushdown accounting. Disclosures are required to be made in the period in which pushdown accounting is applied and are expected to include both qualitative and quantitative information. The new recognition and disclosure requirements became effective on a prospective basis on November 18, 2014. PHI currently anticipates it may be affected by the new guidance if its Merger with Exelon is consummated. |
Fair Value Measurement | Fair Value Measurement (ASC 820) In May 2015, the FASB issued new disclosure requirements for investment fair values. Under the new requirements, investment fair values based on net asset value (NAV) per share will continue to be disclosed, however, a level will not be assigned to those investment fair values. The new requirements are effective for PHI beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented; however, early adoption is permitted. PHI has elected to early adopt the new guidance and implement the change in accounting principle in the fourth quarter of 2015. The impact of this guidance effected the presentation of certain investments that use NAV per share as a practical expedient in Note (9), “Pension and Other Postretirement Benefits” and had no impact to Note (15), “Fair Value Disclosure,” as the financial instruments measured at fair value on a recurring basis and other financial instruments are not based on NAV. |
Presentation of Debt Issuance Costs | Presentation of Debt Issuance Costs (ASC 835) In April 2015, the FASB issued new guidance for the presentation of debt issuance costs on the balance sheet. Debt issuance costs are currently required to be presented on the balance sheet as assets. However, under the new requirements, these debt issuance costs will be offset against the debt to which the costs relate. The new requirements are effective for PHI beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented; however, early adoption is permitted. PHI has elected to early adopt the new guidance in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in PHI’s consolidated balance sheet as of December 31, 2014. December 31, 2014 As Filed Reclassification ASC 835 December 31, 2014 As Adjusted (millions of dollars) Other (within other assets) $ 166 $ (45 ) $ 121 Long-term debt 4,441 (44 ) 4,397 Transition bonds issued by ACE Funding 171 (1 ) 170 |
Balance Sheet Classification of Deferred Taxes (ASC 740) | Balance Sheet Classification of Deferred Taxes (ASC 740) In November 2015, the FASB issued new requirements for the balance sheet classification of deferred taxes. Entities are currently required to present a current and noncurrent deferred tax balance on the balance sheet. Under the new requirements, deferred taxes will only be presented as noncurrent. The new requirements are effective for PHI beginning January 1, 2017, and may be implemented on either a prospective or retrospective basis; however, early adoption is permitted. PHI has elected to early adopt the new guidance on a retrospective basis in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in PHI’s consolidated balance sheet as of December 31, 2014. December 31, 2014 As Filed Reclassification ASC 740 December 31, 2014 As Adjusted (millions of dollars) Deferred income taxes, net (within current assets) $ 50 $ (50 ) $ — Deferred income taxes, net (within other assets) — 17 17 Other (within current liabilities) 314 (9 ) 305 Deferred income tax liabilities, net 3,266 (24 ) 3,242 |
Revenue from Contracts with Customers | Revenue from Contracts with Customers (ASC 606) In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard. The new requirements will be effective for PHI beginning January 1, 2018, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2018. Early adoption is permitted, but not before January 1, 2017. PHI is currently evaluating the potential impact of this new guidance on its consolidated financial statements and which implementation approach to select. |
Business Combination | Business Combination (ASC 805) In September 2015, the FASB issued new guidance on adjustments to provisional amounts recognized in a business combination, which are currently recognized on a retrospective basis. Under the new requirements, adjustments will be recognized in the reporting period in which the adjustments are determined. The effects of changes in depreciation, amortization, or other income arising from changes to the provisional amounts, if any, are included in earnings of the reporting period in which the adjustments to the provisional amounts are determined. An entity is also required to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The new requirements will be effective for PHI beginning January 1, 2016, and are required to be implemented on a prospective basis. Early adoption is permitted. PHI currently anticipates it may be affected by the new guidance if its Merger with Exelon is consummated. |
Potomac Electric Power Co [Member] | |
Use of Estimates | Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the financial statements and accompanying notes. Although Pepco believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates. Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset impairment calculations, pension and other postretirement benefits assumptions, the assessment of the adequacy of the allowance for uncollectible accounts, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, recognition of changes in network service transmission rates for prior service year costs, accrual of loss contingency liabilities for general litigation and auto and other liability claims and income tax provisions and reserves. Additionally, Pepco is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. Pepco records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable. |
Revenue Recognition | Revenue Recognition Pepco recognizes revenue upon distribution of electricity to its customers, including unbilled revenue for services rendered, but not yet billed. Pepco’s unbilled revenue was $76 million and $77 million as of December 31, 2015 and 2014, respectively, and these amounts are included in Accounts receivable. Pepco calculates unbilled revenue using an output-based methodology. This methodology is based on the supply of electricity intended for distribution to customers. The unbilled revenue process requires management to make assumptions and judgments about input factors such as customer sales mix, temperature, and estimated line losses (estimates of electricity expected to be lost in the process of its transmission and distribution to customers). The assumptions and judgments are inherently uncertain and susceptible to change from period to period, and if actual results differ from projected results, the impact could be material. Taxes related to the consumption of electricity by Pepco’s customers, such as fuel, energy, or other similar taxes, are components of Pepco’s tariffs and, as such, are billed to customers and recorded in Operating revenue. Accruals for the remittance of these taxes by Pepco are recorded in Other taxes. |
Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions | Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions Taxes included in Pepco’s gross revenues were $304 million, $304 million and $318 million for the years ended December 31, 2015, 2014 and 2013, respectively. |
Income Taxes | Income Taxes Pepco, as a direct subsidiary of Pepco Holdings, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to Pepco based upon the taxable income or loss amounts, determined on a separate return basis. The financial statements include current and deferred income taxes. Current income taxes represent the amount of tax expected to be reported on Pepco’s state income tax returns and the amount of federal income tax allocated from Pepco Holdings. Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement basis and tax basis of existing assets and liabilities and they are measured using presently enacted tax rates. The portion of Pepco’s deferred tax liability applicable to its utility operations that has not been recovered from utility customers represents income taxes recoverable in the future and is included in Regulatory assets on the balance sheets. See Note (6), “Regulatory Matters,” for additional information. Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes. Pepco recognizes interest on underpayments and overpayments of income taxes, interest on uncertain tax positions, and tax-related penalties in income tax expense. Investment tax credits are being amortized to income over the useful lives of the related property. |
Cash and Cash Equivalents | Cash and Cash Equivalents Cash and cash equivalents include cash on hand, cash invested in money market funds and commercial paper held with original maturities of three months or less. Additionally, deposits in PHI’s money pool, which Pepco and certain other PHI subsidiaries use to manage short-term cash management requirements, are considered cash equivalents. Deposits in the money pool are guaranteed by PHI. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the needs of its participants, which may require PHI to borrow funds for deposit from external sources. |
Restricted Cash Equivalents | Restricted Cash Equivalents The Restricted cash equivalents included in Current assets consist of (i) cash held as collateral that is restricted from use for general corporate purposes and (ii) cash equivalents that are specifically segregated based on management’s intent to use such cash equivalents for a particular purpose. The classification as current conforms to the classification of the related liabilities. |
Accounts Receivable and Allowance for Uncollectible Accounts | Accounts Receivable and Allowance for Uncollectible Accounts Pepco’s Accounts receivable balance primarily consists of customer accounts receivable arising from the sale of goods and services to customers within its service territory, other accounts receivable, and accrued unbilled revenue. Accrued unbilled revenue represents revenue earned in the current period but not billed to the customer until a future date (usually within one month after the receivable is recorded). Pepco maintains an allowance for uncollectible accounts and changes in the allowance are recorded as an adjustment to Other operation and maintenance expense in the statements of income. Pepco determines the amount of the allowance based on specific identification of material amounts at risk by customer and maintains a reserve based on its historical collection experience. The adequacy of this allowance is assessed on a quarterly basis by evaluating all known factors such as the aging of the receivables, historical collection experience, the economic and competitive environment and changes in the creditworthiness of its customers. Accounts receivable are written off in the period in which the receivable is deemed uncollectible and collection efforts have been exhausted. Recoveries of Accounts receivable previously written off are recorded when received. Although Pepco believes its allowance is adequate, it cannot anticipate with any certainty the changes in the financial condition of its customers. As a result, Pepco records adjustments to the allowance for uncollectible accounts in the period in which the new information that requires an adjustment to the reserve becomes known. |
Inventories | Inventories Included in Inventories are transmission and distribution materials and supplies. Pepco utilizes the weighted average cost method of accounting for inventory items. Under this method, an average price is determined for the quantity of units acquired at each price level and is applied to the ending quantity to calculate the total ending inventory balance. Materials and supplies are recorded in Inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed. |
Regulatory Assets and Regulatory Liabilities | Regulatory Assets and Regulatory Liabilities Pepco is regulated by the MPSC and the DCPSC. The transmission of electricity by Pepco is regulated by FERC. Based on the regulatory framework in which it has operated, Pepco has historically applied, and in connection with its transmission and distribution business continues to apply, the Financial Accounting Standards Board (FASB) guidance on regulated operations (Accounting Standards Codification (ASC) 980). The guidance allows regulated entities, in appropriate circumstances, to defer the income statement impact of certain costs that are expected to be recovered in future rates through the establishment of regulatory assets and defer certain revenues that are expected to be refunded to customers through the establishment of regulatory liabilities. Management’s assessment of the probability of recovery of regulatory assets requires judgment and interpretation of laws, regulatory commission orders and other factors. If management subsequently determines, based on changes in facts or circumstances, that a regulatory asset is not probable of recovery, the regulatory asset would be eliminated through a charge to earnings. Effective June 2007, the MPSC approved a bill stabilization adjustment (BSA) mechanism for retail customers. Effective November 2009, the DCPSC approved a BSA for retail customers. For customers to whom the BSA applies, Pepco recognizes distribution revenue based on an approved distribution charge per customer. From a revenue recognition standpoint, the BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during that period. Pursuant to this mechanism, Pepco recognizes either (i) a positive adjustment equal to the amount by which revenue from Maryland and the District of Columbia retail distribution sales falls short of the revenue that Pepco is entitled to earn based on the approved distribution charge per customer, or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco is entitled to earn based on the approved distribution charge per customer (a Revenue Decoupling Adjustment). A net positive Revenue Decoupling Adjustment is recorded as a regulatory asset and a net negative Revenue Decoupling Adjustment is recorded as a regulatory liability. |
Leasing Activities | Leasing Activities Pepco’s lease transactions include office space, equipment, software and vehicles. In accordance with FASB guidance on leases (ASC 840), these leases are classified as either operating leases or capital leases. Operating Leases An operating lease in which Pepco is the lessee generally results in a level income statement charge over the term of the lease, reflecting the rental payments required by the lease agreement. If rental payments are not made on a straight-line basis, Pepco’s policy is to recognize rent expense on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed. Capital Leases For ratemaking purposes, capital leases in which Pepco is the lessee are treated as operating leases; therefore, in accordance with FASB guidance on regulated operations (ASC 980), the amortization of the leased asset is based on the recovery of rental payments through customer rates. Investments in equipment under capital leases are stated at cost, less accumulated depreciation. Depreciation is recorded on a straight-line basis over the equipment’s estimated useful life. |
Property, Plant and Equipment | Property, Plant and Equipment Property, plant and equipment is recorded at original cost, including labor, materials, asset retirement costs and other direct and indirect costs including capitalized interest. The carrying value of Property, plant and equipment is evaluated for impairment whenever circumstances indicate that the carrying value of those assets may not be recoverable. Upon retirement, the cost of regulated property, net of salvage, is charged to Accumulated depreciation. For additional information regarding the treatment of asset removal obligations, see the “Asset Removal Costs” section included in this Note. The annual provision for depreciation on electric property, plant and equipment is computed on a straight-line basis using composite rates by classes of depreciable property. Non-operating and other property is generally depreciated on a straight-line basis over the useful lives of the assets. The system-wide composite annual depreciation rates for the years ended December 31, 2015, 2014 and 2013 for Pepco’s property were approximately 2.3%, 2.3% and 2.2%, respectively. |
Long-Lived Asset Impairment Evaluation | Long-Lived Assets Impairment Evaluation Pepco evaluates certain long-lived assets to be held and used (for example, equipment and real estate) for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Examples of such events or changes include a significant decrease in the market price of a long-lived asset or a significant adverse change in the manner in which an asset is being used or its physical condition. A long-lived asset to be held and used is written down to its estimated fair value if the expected future undiscounted cash flow from the asset is less than its carrying value. For long-lived assets that can be classified as assets to be disposed of by sale, an impairment loss is recognized to the extent that the asset’s carrying value exceeds its estimated fair value including costs to sell. |
Capitalized Interest and Allowance for Funds Used During Construction | Capitalized Interest and Allowance for Funds Used During Construction In accordance with FASB guidance on regulated operations (ASC 980), utilities may capitalize the capital costs of financing the construction of plant and equipment as allowance for funds used during construction (AFUDC). This results in the debt portion of AFUDC being recorded as a reduction of Interest expense and the equity portion of AFUDC being recorded as an increase to Other income in the accompanying statements of income. Pepco recorded AFUDC for borrowed funds of $6 million, $5 million and $5 million for the years ended December 31, 2015, 2014 and 2013, respectively. Pepco recorded amounts for the equity component of AFUDC of $12 million, $10 million and $9 million for the years ended December 31, 2015, 2014 and 2013, respectively. |
Amortization of Debt Issuance and Reacquisition Costs | Amortization of Debt Issuance and Reacquisition Costs Pepco defers and amortizes debt issuance costs and long-term debt premiums and discounts over the lives of the respective debt issuances. When refinancing or redeeming existing debt, any unamortized premiums, discounts and debt issuance costs, as well as debt redemption costs, are classified as regulatory assets and are amortized generally over the life of the new issue. |
Asset Removal Costs | Asset Removal Costs In accordance with FASB guidance on regulated operations (ASC 980), asset removal costs are recorded as regulatory liabilities. At December 31, 2015 and 2014, $58 million and $84 million, respectively, of asset removal costs are included in Regulatory liabilities in the accompanying balance sheets. |
Pension and Postretirement Benefit Plans | Pension and Postretirement Benefit Plans Pepco Holdings sponsors a non-contributory, defined benefit pension plan that covers substantially all employees of Pepco and certain employees of other Pepco Holdings subsidiaries (the PHI Retirement Plan). Pepco Holdings also provides supplemental retirement benefits to certain eligible executives and key employees through nonqualified retirement plans and provides certain postretirement health care and life insurance benefits for eligible retired employees. The PHI Retirement Plan is accounted for in accordance with FASB guidance on retirement benefits (ASC 715). |
Reclassifications | Reclassifications Certain prior period amounts have been reclassified in order to conform to the current period presentation. |
Dividend Restrictions | Dividend Restrictions All of Pepco’s shares of outstanding common stock are held by PHI, its parent company. In addition to its future financial performance, the ability of Pepco to pay dividends to its parent company is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends, and (ii) the prior rights of holders of future preferred stock, if any, and existing and future mortgage bonds and other long-term debt issued by Pepco and any other restrictions imposed in connection with the incurrence of liabilities. Pepco has no shares of preferred stock outstanding. Pepco had approximately $1,118 million and $1,077 million of retained earnings available for payment of common stock dividends at December 31, 2015 and 2014, respectively. These amounts represent the total retained earnings balances at those dates. |
Business Combinations | Business Combinations (ASC 805) In November 2014, the FASB issued new recognition and disclosure requirements related to pushdown accounting. The new recognition requirements grant an acquired entity (or its subsidiaries) the option to elect whether and when a new accounting and reporting basis (pushdown accounting) will be applied when an acquirer obtains control of the acquired entity. This election may be made by the acquired entity (or its subsidiaries) for future change-in-control events or for its most recent change-in-control event, and the acquired entity will be required to determine whether pushdown accounting will be applied in the reporting period in which the change-in-control event occurs or in a subsequent reporting period. The new required disclosures include information that enables financial statement users to evaluate the effects of pushdown accounting. Disclosures are required to be made in the period in which pushdown accounting is applied and are expected to include both qualitative and quantitative information. The new recognition and disclosure requirements became effective on a prospective basis on November 18, 2014. |
Presentation of Debt Issuance Costs | Presentation of Debt Issuance Costs (ASC 835) In April 2015, the FASB issued new guidance for the presentation of debt issuance costs on the balance sheet. Debt issuance costs are currently required to be presented on the balance sheet as assets. However, under the new requirements, these debt issuance costs will be offset against the debt to which the costs relate. The new requirements are effective for Pepco beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented; however, early adoption is permitted. Pepco has elected to early adopt the new guidance in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in Pepco’s balance sheet as of December 31, 2014. December 31, 2014 As Filed Reclassification December 31, 2014 As Adjusted (millions of dollars) Other (within other assets) $ 71 $ (28 ) $ 43 Long-term debt 2,124 (28 ) 2,096 |
Balance Sheet Classification of Deferred Taxes (ASC 740) | Balance Sheet Classification of Deferred Taxes (ASC 740) In November 2015, the FASB issued new requirements for the balance sheet classification of deferred taxes. Entities are currently required to present a current and noncurrent deferred tax balance on the balance sheet. Under the new requirements, deferred taxes will only be presented as noncurrent. The new requirements are be effective for PHI beginning January 1, 2017, and may be implemented on either a prospective or retrospective basis; however, early adoption is permitted. PHI has elected to early adopt the new guidance on a retrospective basis in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in Pepco’s balance sheet as of December 31, 2014. December 31, 2014 Reclassification December 31, 2014 (millions of dollars) Deferred income taxes, net (within current assets) $ 14 $ (14 ) $ — Other (within current liabilities) 102 (9 ) 93 Deferred income tax liabilities, net 1,584 (5 ) 1,579 |
Revenue from Contracts with Customers | Revenue from Contracts with Customers (ASC 606) In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard. The new requirements will be effective for Pepco beginning January 1, 2018, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2018. Early adoption is permitted, but not before January 1, 2017. Pepco is currently evaluating the potential impact of this new guidance on its financial statements and which implementation approach to select. |
Business Combination | Business Combination (ASC 805) In September 2015, the FASB issued new guidance on adjustments to provisional amounts recognized in a business combination, which are currently recognized on a retrospective basis. Under the new requirements, adjustments will be recognized in the reporting period in which the adjustments are determined. The effects of changes in depreciation, amortization, or other income arising from changes to the provisional amounts, if any, are included in earnings of the reporting period in which the adjustments to the provisional amounts are determined. An entity is also required to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The new requirements will be effective for Pepco beginning January 1, 2016, and are required to be implemented on a prospective basis. Early adoption is permitted. Pepco currently anticipates it may be affected by the new guidance if its Merger with Exelon is consummated. |
Investment in Trust | Investment in Trust Represents assets held in a trust for the benefit of participants in the Pepco Owned Life Insurance plan. |
Delmarva Power & Light Co/De [Member] | |
Consolidation of Variable Interest Entities | Consolidation of Variable Interest Entities DPL assesses its contractual arrangements with variable interest entities (VIEs) to determine whether it is the primary beneficiary and thereby has to consolidate the entities in accordance with FASB ASC 810. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests. See Note (17), “Variable Interest Entities,” for additional information. |
Use of Estimates | Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the financial statements and accompanying notes. Although DPL believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates. Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset and goodwill impairment calculations, fair value calculations for derivative instruments, pension and other postretirement benefits assumptions, the assessment of the adequacy of the allowance for uncollectible accounts, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, recognition of changes in network service transmission rates for prior service year costs, accrual of loss contingency liabilities for general litigation and auto and other liability claims, and income tax provisions and reserves. Additionally, DPL is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. DPL records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable. |
Revenue Recognition | Revenue Recognition DPL recognizes revenue upon distribution of electricity and natural gas to its customers, including unbilled revenue for services rendered, but not yet billed. DPL’s unbilled revenue was $37 million and $63 million as of December 31, 2015 and 2014, respectively, and these amounts are included in Accounts receivable. DPL calculates unbilled revenue using an output-based methodology. This methodology is based on the supply of electricity or natural gas intended for distribution to customers. The unbilled revenue process requires management to make assumptions and judgments about input factors such as customer sales mix, temperature, and estimated line losses (estimates of electricity and natural gas expected to be lost in the process of its transmission and distribution to customers). The assumptions and judgments are inherently uncertain and susceptible to change from period to period, and if the actual results differ from the projected results, the impact could be material. Revenue from non-regulated electricity and natural gas sales is included in Electric revenue and Natural gas revenue, respectively. Taxes related to the consumption of electricity and natural gas by DPL’s customers, such as fuel, energy, or other similar taxes, are components of DPL’s tariffs and, as such, are billed to customers and recorded in Operating revenue. Accruals for the remittance of these taxes by DPL are recorded in Other taxes. |
Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions | Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions Taxes included in DPL’s gross revenues were $18 million, $16 million and $17 million for the years ended December 31, 2015, 2014 and 2013, respectively. |
Accounting for Derivatives | Accounting for Derivatives DPL uses derivative instruments primarily to reduce natural gas commodity price volatility and to limit its customers’ exposure to natural gas price fluctuations under a hedging program approved by the DPSC. Derivatives are recorded in the balance sheets as Derivative assets or Derivative liabilities and measured at fair value. DPL enters physical natural gas contracts as part of the hedging program that qualify as normal purchases or normal sales, which are not required to be recorded in the financial statements until settled. DPL’s capacity contracts are not classified as derivatives. Changes in the fair value of derivatives that are not designated as cash flow hedges are reflected in income. All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all gains and losses related to hedging activities, are fully recoverable through the fuel adjustment clause approved by the DPSC, and are deferred under Financial Accounting Standards Board (FASB) guidance on regulated operations (Accounting Standards Codification (ASC) 980) until recovered. |
Income Taxes | Income Taxes DPL, as an indirect subsidiary of Pepco Holdings, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to DPL based upon the taxable income or loss amounts, determined on a separate return basis. The accompanying financial statements include current and deferred income taxes. Current income taxes represent the amount of tax expected to be reported on DPL’s state income tax returns and the amount of federal income tax allocated from Pepco Holdings. Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement basis and tax basis of existing assets and liabilities, and they are measured using presently enacted tax rates. The portion of DPL’s deferred tax liability applicable to its utility operations that has not been recovered from utility customers represents income taxes recoverable in the future and is included in Regulatory assets on the accompanying balance sheets. See Note (7), “Regulatory Matters,” for additional information. Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes. DPL recognizes interest on underpayments and overpayments of income taxes, interest on uncertain tax positions, and tax-related penalties in income tax expense. Investment tax credits are being amortized to income over the useful lives of the related property. |
Cash and Cash Equivalents | Cash and Cash Equivalents Cash and cash equivalents include cash on hand, cash invested in money market funds and commercial paper held with original maturities of three months or less. Additionally, deposits in PHI’s money pool, which DPL and certain other PHI subsidiaries use to manage short-term cash management requirements, are considered cash equivalents. Deposits in the money pool are guaranteed by PHI. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the needs of its participants, which may require PHI to borrow funds for deposit from external sources. |
Accounts Receivable and Allowance for Uncollectible Accounts | Accounts Receivable and Allowance for Uncollectible Accounts DPL’s Accounts receivable balance primarily consists of customer accounts receivable arising from the sale of goods and services to customers within its service territory, other accounts receivable, and accrued unbilled revenue. Accrued unbilled revenue represents revenue earned in the current period but not billed to the customer until a future date (usually within one month after the receivable is recorded). DPL maintains an allowance for uncollectible accounts and changes in the allowance are recorded as an adjustment to Other operation and maintenance expense in the accompanying statements of income. DPL determines the amount of the allowance based on specific identification of material amounts at risk by customer and maintains a reserve based on its historical collection experience. The adequacy of this allowance is assessed on a quarterly basis by evaluating all known factors such as the aging of the receivables, historical collection experience, the economic and competitive environment and changes in the creditworthiness of its customers. Accounts receivable are written off in the period in which the receivable is deemed uncollectible and collection efforts have been exhausted. Recoveries of Accounts receivable previously written off are recorded when received. Although DPL believes its allowance is adequate, it cannot anticipate with any certainty the changes in the financial condition of its customers. As a result, DPL records adjustments to the allowance for uncollectible accounts in the period in which the new information that requires an adjustment to the reserve becomes known. |
Inventories | Inventories Included in Inventories are transmission and distribution materials and supplies and natural gas. DPL utilizes the weighted average cost method of accounting for inventory items. Under this method, an average price is determined for the quantity of units acquired at each price level and is applied to the ending quantity to calculate the total ending inventory balance. Materials and supplies are recorded in Inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed. The cost of natural gas, including transportation costs, is included in Inventory when purchased and charged to Gas purchased expense when used. |
Goodwill | Goodwill Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired at the acquisition date. DPL tests its goodwill for impairment annually as of November 1 and whenever an event occurs or circumstances change in the interim that would more likely than not (that is, a greater than 50% chance) reduce the estimated fair value of DPL below the carrying amount of its net assets. Factors that may result in an interim impairment test include, but are not limited to: a change in the identified reporting unit, an adverse change in business conditions, an adverse regulatory action, or an impairment of DPL’s long-lived assets. DPL performed its most recent annual impairment test as of November 1, 2015, and its goodwill was not impaired as described in Note (6), “Goodwill.” |
Regulatory Assets and Regulatory Liabilities | Regulatory Assets and Regulatory Liabilities Certain aspects of DPL’s business are subject to regulation by the DPSC and the MPSC. The transmission of electricity by DPL is regulated by FERC. DPL’s interstate transportation and wholesale sale of natural gas are regulated by FERC. Based on the regulatory framework in which it has operated, DPL has historically applied, and in connection with its transmission and distribution business continues to apply, FASB guidance on regulated operations (ASC 980). The guidance allows regulated entities, in appropriate circumstances, to defer the income statement impact of certain costs that are expected to be recovered in future rates through the establishment of regulatory assets and defer certain revenues that are expected to be refunded to customers through the establishment of regulatory liabilities. Management’s assessment of the probability of recovery of regulatory assets requires judgment and interpretation of laws, regulatory commission orders and other factors. If management subsequently determines, based on changes in facts or circumstances, that a regulatory asset is not probable of recovery, the regulatory asset would be eliminated through a charge to earnings. Effective June 2007, the MPSC approved a bill stabilization adjustment (BSA) mechanism for retail customers. For customers to whom the BSA applies, DPL recognizes distribution revenue based on an approved distribution charge per customer. From a revenue recognition standpoint, the BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during that period. Pursuant to this mechanism, DPL recognizes either (i) a positive adjustment equal to the amount by which revenue from Maryland retail distribution sales falls short of the revenue that DPL is entitled to earn based on the approved distribution charge per customer, or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that DPL is entitled to earn based on the approved distribution charge per customer (a Revenue Decoupling Adjustment). A net positive Revenue Decoupling Adjustment is recorded as a regulatory asset and a net negative Revenue Decoupling Adjustment is recorded as a regulatory liability. |
Leasing Activities | Leasing Activities DPL’s lease transactions include plant, office space, equipment, software, vehicles and elements of power purchase agreements (PPAs). In accordance with FASB guidance on leases (ASC 840), these leases are classified as operating leases. Operating Leases An operating lease in which DPL is the lessee generally results in a level income statement charge over the term of the lease, reflecting the rental payments required by the lease agreement. If rental payments are not made on a straight-line basis, DPL’s policy is to recognize rent expense on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed. Arrangements Containing a Lease PPAs are deemed to contain a lease if the arrangement conveys the right to control the use of property, plant or equipment. If so, DPL determines the appropriate lease accounting classification. |
Property, Plant and Equipment | Property, Plant and Equipment Property, plant and equipment is recorded at original cost, including labor, materials, asset retirement costs and other direct and indirect costs including capitalized interest. The carrying value of Property, plant and equipment is evaluated for impairment whenever circumstances indicate that the carrying value of those assets may not be recoverable. Upon retirement, the cost of regulated property, net of salvage, is charged to Accumulated depreciation. For additional information regarding the treatment of asset retirement obligations, see the “Asset Removal Costs” section included in this Note. The annual provision for depreciation on electric and natural gas property, plant and equipment is computed on a straight-line basis using composite rates by classes of depreciable property. Non-operating and other property is generally depreciated on a straight-line basis over the useful lives of the assets. The system-wide composite annual depreciation rate for each of the years ended December 31, 2015, 2014 and 2013 for DPL’s property was approximately 2.6%. |
Long-Lived Asset Impairment Evaluation | Long-Lived Assets Impairment Evaluation DPL evaluates certain long-lived assets to be held and used (for example, equipment and real estate) for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Examples of such events or changes include a significant decrease in the market price of a long-lived asset or a significant adverse change in the manner in which an asset is being used or its physical condition. A long-lived asset to be held and used is written down to its estimated fair value if the expected future undiscounted cash flow from the asset is less than its carrying value. For long-lived assets that can be classified as assets to be disposed of by sale, an impairment loss is recognized to the extent that the assets’ carrying value exceeds its estimated fair value including costs to sell. |
Capitalized Interest and Allowance for Funds Used During Construction | Capitalized Interest and Allowance for Funds Used During Construction In accordance with FASB guidance on regulated operations (ASC 980), utilities may capitalize the capital costs of financing the construction of plant and equipment as allowance for funds used during construction (AFUDC). This results in the debt portion of AFUDC being recorded as a reduction of Interest expense and the equity portion of AFUDC being recorded as an increase to Other income in the accompanying statements of income. DPL recorded AFUDC for borrowed funds of $1 million, $1 million and $2 million for the years ended December 31, 2015, 2014 and 2013, respectively. DPL recorded amounts for the equity component of AFUDC of $1 million, $2 million and $2 million for the years ended December 31, 2015, 2014 and 2013, respectively. |
Amortization of Debt Issuance and Reacquisition Costs | Amortization of Debt Issuance and Reacquisition Costs DPL defers and amortizes debt issuance costs and long-term debt premiums and discounts over the lives of the respective debt issuances. When refinancing or redeeming existing debt, any unamortized premiums, discounts and debt issuance costs, as well as debt redemption costs, are classified as regulatory assets and are amortized generally over the life of the original issue. |
Asset Removal Costs | Asset Removal Costs In accordance with FASB guidance on regulated operations (ASC 980), asset removal costs are recorded as regulatory liabilities. At December 31, 2015 and 2014, $153 million and $166 million, respectively, of asset removal costs are included in Regulatory liabilities in the accompanying balance sheets. |
Pension and Postretirement Benefit Plans | Pension and Postretirement Benefit Plans Pepco Holdings sponsors a non-contributory, defined benefit pension plan that covers substantially all employees of DPL and certain employees of other Pepco Holdings subsidiaries (the PHI Retirement Plan). Pepco Holdings also provides supplemental retirement benefits to certain eligible executives and key employees through nonqualified retirement plans and provides certain postretirement health care and life insurance benefits for eligible retired employees. The PHI Retirement Plan is accounted for in accordance with FASB guidance on retirement benefits (ASC 715). |
Reclassifications | Reclassifications Certain prior period amounts have been reclassified in order to conform to the current period presentation. |
Dividend Restrictions | Dividend Restrictions All of DPL’s shares of outstanding common stock are held by Conectiv, its parent company. In addition to its future financial performance, the ability of DPL to pay dividends to its parent company is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends, and (ii) the prior rights of holders of future preferred stock, if any, and existing and future mortgage bonds and other long-term debt issued by DPL and any other restrictions imposed in connection with the incurrence of liabilities. DPL has no shares of preferred stock outstanding. DPL had approximately $625 million and $641 million of retained earnings available for payment of common stock dividends at December 31, 2015 and 2014, respectively. These amounts represent the total retained earnings balances at those dates. |
Business Combinations | Business Combinations (ASC 805) In November 2014, the FASB issued new recognition and disclosure requirements related to pushdown accounting. The new recognition requirements grant an acquired entity (or its subsidiaries) the option to elect whether and when a new accounting and reporting basis (pushdown accounting) will be applied when an acquirer obtains control of the acquired entity. This election may be made by the acquired entity (or its subsidiaries) for future change-in-control events or for its most recent change-in-control event, and the acquired entity will be required to determine whether pushdown accounting will be applied in the reporting period in which the change-in-control event occurs or in a subsequent reporting period. The new required disclosures include information that enables financial statement users to evaluate the effects of pushdown accounting. Disclosures are required to be made in the period in which pushdown accounting is applied and are expected to include both qualitative and quantitative information. The new recognition and disclosure requirements became effective on a prospective basis on November 18, 2014. |
Presentation of Debt Issuance Costs | Presentation of Debt Issuance Costs (ASC 835) In April 2015, the FASB issued new guidance for the presentation of debt issuance costs on the balance sheet. Debt issuance costs are currently required to be presented on the balance sheet as assets. However, under the new requirements, these debt issuance costs will be offset against the debt to which the costs relate. The new requirements are effective for DPL beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented; however, early adoption is permitted. DPL has elected to early adopt the new guidance in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in DPL’s balance sheet as of December 31, 2014. December 31, 2014 As Filed Reclassification ASC 835 December 31, 2014 As Adjusted (millions of dollars) Other (within other assets) $ 12 $ (8 ) $ 4 Long-term debt 971 (8 ) 963 |
Balance Sheet Classification of Deferred Taxes (ASC 740) | Balance Sheet Classification of Deferred Taxes (ASC 740) In November 2015, the FASB issued new requirements for the balance sheet classification of deferred taxes. Entities are currently required to present a current and noncurrent deferred tax balance on the balance sheet. Under the new requirements, deferred taxes will only be presented as noncurrent. The new requirements are effective for PHI beginning January 1, 2017, and may be implemented on either a prospective or retrospective basis; however, early adoption is permitted. PHI has elected to early adopt the new guidance on a retrospective basis in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in DPL’s balance sheet as of December 31, 2014. December 31, 2014 As Filed Reclassification ASC 740 December 31, 2014 As Adjusted (millions of dollars) Deferred income taxes, net (within current assets) $ 16 $ (16 ) $ — Other (within current liabilities) 42 (1 ) 41 Deferred income tax liabilities, net 893 (15 ) 878 |
Revenue from Contracts with Customers | Revenue from Contracts with Customers (ASC 606) In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard. The new requirements will be effective for DPL beginning January 1, 2018, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2018. Early adoption is permitted, but not before January 1, 2017. DPL is currently evaluating the potential impact of this new guidance on its financial statements and which implementation approach to select. |
Business Combination | Business Combination (ASC 805) In September 2015, the FASB issued new guidance on adjustments to provisional amounts recognized in a business combination, which are currently recognized on a retrospective basis. Under the new requirements, adjustments will be recognized in the reporting period in which the adjustments are determined. The effects of changes in depreciation, amortization, or other income arising from changes to the provisional amounts, if any, are included in earnings of the reporting period in which the adjustments to the provisional amounts are determined. An entity is also required to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The new requirements will be effective for DPL beginning January 1, 2016, and are required to be implemented on a prospective basis. Early adoption is permitted. DPL currently anticipates it may be affected by the new guidance if its Merger with Exelon is consummated. |
Atlantic City Electric Co [Member] | |
Consolidation Policy | Consolidation Policy The accompanying consolidated financial statements include the accounts of ACE and its wholly owned subsidiary Atlantic City Electric Transition Funding, LLC (ACE Funding). All intercompany balances and transactions between subsidiaries have been eliminated. ACE uses the equity method to report investments, corporate joint ventures, partnerships, and affiliated companies where it holds an interest and can exercise significant influence over the operations and policies of the entity. Certain transmission and other facilities currently held are consolidated in proportion to ACE’s percentage interest in the facility. |
Consolidation of Variable Interest Entities | Consolidation of Variable Interest Entities ACE assesses its contractual arrangements with variable interest entities (VIEs) to determine whether it is the primary beneficiary and thereby has to consolidate the entities in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 810. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests. See Note (16), “Variable Interest Entities,” for additional information. |
Use of Estimates | Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the consolidated financial statements and accompanying notes. Although ACE believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates. Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset impairment calculations, fair value calculations for derivative instruments, pension and other postretirement benefits assumptions, the assessment of the adequacy of the allowance for uncollectible accounts, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, recognition of changes in network service transmission rates for prior service year costs, accrual of loss contingency liabilities for general litigation and auto and other liability claims, and income tax provisions and reserves. Additionally, ACE is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. ACE records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable. |
Revenue Recognition | Revenue Recognition ACE recognizes revenue upon distribution of electricity to its customers, including unbilled revenue for electricity delivered but not yet billed. ACE’s unbilled revenue was $26 million and $32 million as of December 31, 2015 and 2014, respectively, and these amounts are included in Accounts receivable. ACE calculates unbilled revenue using an output-based methodology. This methodology is based on the supply of electricity intended for distribution to customers. The unbilled revenue process requires management to make assumptions and judgments about input factors such as customer sales mix, temperature, and estimated line losses (estimates of electricity expected to be lost in the process of its transmission and distribution to customers). The assumptions and judgments are inherently uncertain and susceptible to change from period to period, and if the actual results differ from the projected results, the impact could be material. Taxes related to the consumption of electricity by ACE’s customers are a component of ACE’s tariffs and, as such, are billed to customers and recorded in Operating revenue. Accruals for the remittance of these taxes by ACE are recorded in Other taxes. |
Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions | Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions Taxes included in ACE’s gross revenues were zero, $1 million and $11 million for the years ended December 31, 2015, 2014 and 2013, respectively. |
Income Taxes | Income Taxes ACE, as an indirect subsidiary of Pepco Holdings, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to ACE based upon the taxable income or loss amounts, determined on a separate return basis. The consolidated financial statements include current and deferred income taxes. Current income taxes represent the amount of tax expected to be reported on ACE’s state income tax returns and the amount of federal income tax allocated from Pepco Holdings. Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement basis and tax basis of existing assets and liabilities, and they are measured using presently enacted tax rates. The portion of ACE’s deferred tax liability applicable to its utility operations that has not been recovered from utility customers represents income taxes recoverable in the future and is included in Regulatory assets on the consolidated balance sheets. See Note (6), “Regulatory Matters,” for additional information. Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes. ACE recognizes interest on underpayments and overpayments of income taxes, interest on uncertain tax positions, and tax-related penalties in income tax expense. Investment tax credits are being amortized to income over the useful lives of the related property. |
Cash and Cash Equivalents | Cash and Cash Equivalents Cash and cash equivalents include cash on hand, cash invested in money market funds and commercial paper held with original maturities of three months or less. Additionally, deposits in PHI’s money pool, which ACE and certain other PHI subsidiaries use to manage short-term cash management requirements, are considered cash equivalents. Deposits in the money pool are guaranteed by PHI. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the needs of its participants, which may require PHI to borrow funds for deposit from external sources. |
Restricted Cash Equivalents | Restricted Cash Equivalents The Restricted cash equivalents included in Current assets and the Restricted cash equivalents included in Other assets consist of (i) cash held as collateral that is restricted from use for general corporate purposes and (ii) cash equivalents that are specifically segregated based on management’s intent to use such cash equivalents for a particular purpose. The classification as current or non-current conforms to the classification of the related liabilities. |
Accounts Receivable and Allowance for Uncollectible Accounts | Accounts Receivable and Allowance for Uncollectible Accounts ACE’s Accounts receivable balance primarily consists of customer accounts receivable arising from the sale of goods and services to customers within its service territories, other accounts receivable, and accrued unbilled revenue. Accrued unbilled revenue represents revenue earned in the current period but not billed to the customer until a future date (usually within one month after the receivable is recorded). ACE maintains an allowance for uncollectible accounts and changes in the allowance are recorded as an adjustment to Other operation and maintenance expense in the consolidated statements of income. ACE determines the amount of the allowance based on specific identification of material amounts at risk by customer and maintains a reserve based on its historical collection experience. The adequacy of this allowance is assessed on a quarterly basis by evaluating all known factors such as the aging of the receivables, historical collection experience, the economic and competitive environment and changes in the creditworthiness of its customers. Accounts receivable are written off in the period in which the receivable is deemed uncollectible and collection efforts have been exhausted. Recoveries of Accounts receivable previously written off are recorded when received. Although ACE believes its allowance is adequate, it cannot anticipate with any certainty the changes in the financial condition of its customers. As a result, ACE records adjustments to the allowance for uncollectible accounts in the period in which the new information that requires an adjustment to the reserve becomes known. |
Inventories | Inventories Included in inventories are transmission and distribution materials and supplies. ACE utilizes the weighted average cost method of accounting for inventory items. Under this method, an average price is determined for the quantity of units acquired at each price level and is applied to the ending quantity to calculate the total ending inventory balance. Materials and supplies are recorded in Inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed. |
Regulatory Assets and Regulatory Liabilities | Regulatory Assets and Regulatory Liabilities Certain aspects of ACE’s business are subject to regulation by the NJBPU. The transmission of electricity by ACE is regulated by FERC. Based on the regulatory framework in which it has operated, ACE has historically applied, and in connection with its transmission and distribution business continues to apply, FASB guidance on regulated operations (ASC 980). The guidance allows regulated entities, in appropriate circumstances, to defer the income statement impact of certain costs that are expected to be recovered in future rates through the establishment of regulatory assets and defer certain revenues that are expected to be refunded to customers through the establishment of regulatory liabilities. Management’s assessment of the probability of recovery of regulatory assets requires judgment and interpretation of laws, regulatory commission orders and other factors. If management subsequently determines, based on changes in facts or circumstances, that a regulatory asset is not probable of recovery, the regulatory asset would be eliminated through a charge to earnings. |
Leasing Activities | Leasing Activities ACE’s lease transactions include plant, office space, equipment, software, vehicles and elements of power purchase agreements (PPAs). In accordance with FASB guidance on leases (ASC 840), these leases are classified as operating leases. Operating Leases An operating lease in which ACE is the lessee generally results in a level income statement charge over the term of the lease, reflecting the rental payments required by the lease agreement. If rental payments are not made on a straight-line basis, ACE’s policy is to recognize rent expense on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed. Arrangements Containing a Lease PPAs are deemed to contain a lease if the arrangement conveys the right to control the use of property, plant or equipment. If so, ACE determines the appropriate lease accounting classification. |
Property, Plant and Equipment | Property, Plant and Equipment Property, plant and equipment is recorded at original cost, including labor, materials, asset retirement costs and other direct and indirect costs, including capitalized interest. The carrying value of Property, plant and equipment is evaluated for impairment whenever circumstances indicate that the carrying value of those assets may not be recoverable. Upon retirement, the cost of regulated property, net of salvage, is charged to accumulated depreciation. The annual provision for depreciation on electric property, plant and equipment is computed on a straight-line basis using composite rates by classes of depreciable property. Non-operating and other property is generally depreciated on a straight-line basis over the useful lives of the assets. The system-wide composite annual depreciation rates for the years ended December 31, 2015, 2014 and 2013 for ACE’s property were approximately 2.6%, 2.6% and 2.8%, respectively. |
Long-Lived Asset Impairment Evaluation | Long-Lived Asset Impairment Evaluation ACE evaluates certain long-lived assets to be held and used (for example, equipment and real estate) for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Examples of such events or changes include a significant decrease in the market price of a long-lived asset or a significant adverse change in the manner in which an asset is being used or its physical condition. A long-lived asset to be held and used is written down to its estimated fair value if the expected future undiscounted cash flow from the asset is less than its carrying value. For long-lived assets that can be classified as assets to be disposed of by sale, an impairment loss is recognized to the extent that the asset’s carrying value exceeds its estimated fair value including costs to sell. |
Capitalized Interest and Allowance for Funds Used During Construction | Capitalized Interest and Allowance for Funds Used During Construction In accordance with FASB guidance on regulated operations (ASC 980), utilities may capitalize the capital costs of financing the construction of plant and equipment as allowance for funds used during construction (AFUDC). This results in the debt portion of AFUDC being recorded as a reduction of Interest expense and the equity portion of AFUDC being recorded as an increase to Other income in the accompanying consolidated statements of income. ACE recorded AFUDC for borrowed funds of $1 million, $1 million and less than $1 million for the years ended December 31, 2015, 2014 and 2013, respectively. ACE recorded amounts for the equity component of AFUDC of $1 million, $1 million and less than $1 million for the years ended December 31, 2015, 2014 and 2013, respectively. |
Amortization of Debt Issuance and Reacquisition Costs | Amortization of Debt Issuance and Reacquisition Costs ACE defers and amortizes debt issuance costs and long-term debt premiums and discounts over the lives of the respective debt issuances. When refinancing or redeeming existing debt, any unamortized premiums, discounts and debt issuance costs, as well as debt redemption costs, are classified as regulatory assets and are amortized generally over the life of the original issue. |
Pension and Postretirement Benefit Plans | Pension and Postretirement Benefit Plans Pepco Holdings sponsors a non-contributory, defined benefit pension plan that covers substantially all employees of ACE and certain employees of other Pepco Holdings subsidiaries (the PHI Retirement Plan). Pepco Holdings also provides supplemental retirement benefits to certain eligible executives and key employees through nonqualified retirement plans and provides certain postretirement health care and life insurance benefits for eligible retired employees. The PHI Retirement Plan is accounted for in accordance with FASB guidance on retirement benefits (ASC 715). |
Reclassifications | Reclassifications Certain prior period amounts have been reclassified in order to conform to the current period presentation. |
Dividend Restrictions | Dividend Restrictions All of ACE’s shares of outstanding common stock are held by Conectiv, its parent company. In addition to its future financial performance, the ability of ACE to pay dividends to its parent company is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends and the regulatory requirement that ACE obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%; (ii) the prior rights of holders of future preferred stock, if any, and existing and future mortgage bonds and other long-term debt issued by ACE and any other restrictions imposed in connection with the incurrence of liabilities; and (iii) certain provisions of ACE’s charter that impose restrictions on payment of common stock dividends for the benefit of preferred stockholders. Currently, the restriction in the ACE charter does not limit its ability to pay common stock dividends. ACE had approximately $235 million and $209 million of retained earnings available for payment of common stock dividends at December 31, 2015 and 2014, respectively. These amounts represent the total retained earnings balances at those dates. |
Business Combinations | Business Combinations (ASC 805) In November 2014, the FASB issued new recognition and disclosure requirements related to pushdown accounting. The new recognition requirements grant an acquired entity (or its subsidiaries) the option to elect whether and when a new accounting and reporting basis (pushdown accounting) will be applied when an acquirer obtains control of the acquired entity. This election may be made by the acquired entity (or its subsidiaries) for future change-in-control events or for its most recent change-in-control event, and the acquired entity will be required to determine whether pushdown accounting will be applied in the reporting period in which the change-in-control event occurs or in a subsequent reporting period. The new required disclosures include information that enables financial statement users to evaluate the effects of pushdown accounting. Disclosures are required to be made in the period in which pushdown accounting is applied and are expected to include both qualitative and quantitative information. The new recognition and disclosure requirements became effective on a prospective basis on November 18, 2014. |
Presentation of Debt Issuance Costs | Presentation of Debt Issuance Costs (ASC 835) In April 2015, the FASB issued new guidance for the presentation of debt issuance costs on the balance sheet. Debt issuance costs are currently required to be presented on the balance sheet as assets. However, under the new requirements, these debt issuance costs will be offset against the debt to which the costs relate. The new requirements are effective for ACE beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented; however, early adoption is permitted. ACE has elected to early adopt the new guidance in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in ACE’s consolidated balance sheet as of December 31, 2014. December 31, 2014 Reclassification December 31, 2014 (millions of dollars) Other (within other assets) $ 12 $ (7 ) $ 5 Long-term debt 888 (6 ) 882 Transition bonds issued by ACE Funding 171 (1 ) 170 |
Balance Sheet Classification of Deferred Taxes (ASC 740) | Balance Sheet Classification of Deferred Taxes (ASC 740) In November 2015, the FASB issued new requirements for the balance sheet classification of deferred taxes. Entities are currently required to present a current and noncurrent deferred tax balance on the balance sheet. Under the new requirements, deferred taxes will only be presented as noncurrent. The new requirements are effective for PHI beginning January 1, 2017, and may be implemented on either a prospective or retrospective basis; however, early adoption is permitted. PHI has elected to early adopt the new guidance on a retrospective basis in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in ACE’s consolidated balance sheet as of December 31, 2014. December 31, 2014 Reclassification December 31, 2014 (millions of dollars) Prepaid expenses and other $ 13 $ (10 ) $ 3 Deferred income tax liabilities, net 865 (10 ) 855 |
Revenue from Contracts with Customers | Revenue from Contracts with Customers (ASC 606) In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard. The new requirements will be effective for ACE beginning January 1, 2018, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2018. Early adoption is permitted, but not before January 1, 2017. ACE is currently evaluating the potential impact of this new guidance on its consolidated financial statements and which implementation approach to select. |
Business Combination | Business Combination (ASC 805) In September 2015, the FASB issued new guidance on adjustments to provisional amounts recognized in a business combination, which are currently recognized on a retrospective basis. Under the new requirements, adjustments will be recognized in the reporting period in which the adjustments are determined. The effects of changes in depreciation, amortization, or other income arising from changes to the provisional amounts, if any, are included in earnings of the reporting period in which the adjustments to the provisional amounts are determined. An entity is also required to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The new requirements will be effective for ACE beginning January 1, 2016, and are required to be implemented on a prospective basis. Early adoption is permitted. ACE currently anticipates it may be affected by the new guidance if its Merger with Exelon is consummated. |
Significant Accounting Polici34
Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Annual Depreciation Rates | The table below provides system-wide composite annual depreciation rates for the years ended December 31, 2015, 2014 and 2013. Transmission and 2015 2014 2013 2015 2014 2013 Pepco 2.3 % 2.3 % 2.2 % — — — DPL 2.6 % 2.6 % 2.6 % — — — ACE 2.6 % 2.6 % 2.8 % — — — Pepco Energy Services — — — 0.6 % 1.2 % 0.4 % |
Newly Adopted Accounting Stan35
Newly Adopted Accounting Standards (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Presentation Of Debt Issuance Costs [Member] | |
Effects of the Retrospective Application of Newly Adopted Accounting Standards on Reported Balances | The table below illustrates the effects of the retrospective application on reported balances in PHI’s consolidated balance sheet as of December 31, 2014. December 31, 2014 As Filed Reclassification ASC 835 December 31, 2014 As Adjusted (millions of dollars) Other (within other assets) $ 166 $ (45 ) $ 121 Long-term debt 4,441 (44 ) 4,397 Transition bonds issued by ACE Funding 171 (1 ) 170 |
Balance Sheet Classification Of Deferred Taxes [Member] | |
Effects of the Retrospective Application of Newly Adopted Accounting Standards on Reported Balances | The table below illustrates the effects of the retrospective application on reported balances in PHI’s consolidated balance sheet as of December 31, 2014. December 31, 2014 As Filed Reclassification ASC 740 December 31, 2014 As Adjusted (millions of dollars) Deferred income taxes, net (within current assets) $ 50 $ (50 ) $ — Deferred income taxes, net (within other assets) — 17 17 Other (within current liabilities) 314 (9 ) 305 Deferred income tax liabilities, net 3,266 (24 ) 3,242 |
Atlantic City Electric Co [Member] | Presentation Of Debt Issuance Costs [Member] | |
Effects of the Retrospective Application of Newly Adopted Accounting Standards on Reported Balances | The table below illustrates the effects of the retrospective application on reported balances in ACE’s consolidated balance sheet as of December 31, 2014. December 31, 2014 Reclassification December 31, 2014 (millions of dollars) Other (within other assets) $ 12 $ (7 ) $ 5 Long-term debt 888 (6 ) 882 Transition bonds issued by ACE Funding 171 (1 ) 170 |
Atlantic City Electric Co [Member] | Balance Sheet Classification Of Deferred Taxes [Member] | |
Effects of the Retrospective Application of Newly Adopted Accounting Standards on Reported Balances | The table below illustrates the effects of the retrospective application on reported balances in ACE’s consolidated balance sheet as of December 31, 2014. December 31, 2014 Reclassification December 31, 2014 (millions of dollars) Prepaid expenses and other $ 13 $ (10 ) $ 3 Deferred income tax liabilities, net 865 (10 ) 855 |
Potomac Electric Power Co [Member] | Presentation Of Debt Issuance Costs [Member] | |
Effects of the Retrospective Application of Newly Adopted Accounting Standards on Reported Balances | The table below illustrates the effects of the retrospective application on reported balances in Pepco’s balance sheet as of December 31, 2014. December 31, 2014 As Filed Reclassification December 31, 2014 As Adjusted (millions of dollars) Other (within other assets) $ 71 $ (28 ) $ 43 Long-term debt 2,124 (28 ) 2,096 |
Potomac Electric Power Co [Member] | Balance Sheet Classification Of Deferred Taxes [Member] | |
Effects of the Retrospective Application of Newly Adopted Accounting Standards on Reported Balances | The table below illustrates the effects of the retrospective application on reported balances in Pepco’s balance sheet as of December 31, 2014. December 31, 2014 Reclassification December 31, 2014 (millions of dollars) Deferred income taxes, net (within current assets) $ 14 $ (14 ) $ — Other (within current liabilities) 102 (9 ) 93 Deferred income tax liabilities, net 1,584 (5 ) 1,579 |
Delmarva Power & Light Co/De [Member] | Presentation Of Debt Issuance Costs [Member] | |
Effects of the Retrospective Application of Newly Adopted Accounting Standards on Reported Balances | The table below illustrates the effects of the retrospective application on reported balances in DPL’s balance sheet as of December 31, 2014. December 31, 2014 As Filed Reclassification ASC 835 December 31, 2014 As Adjusted (millions of dollars) Other (within other assets) $ 12 $ (8 ) $ 4 Long-term debt 971 (8 ) 963 |
Delmarva Power & Light Co/De [Member] | Balance Sheet Classification Of Deferred Taxes [Member] | |
Effects of the Retrospective Application of Newly Adopted Accounting Standards on Reported Balances | The table below illustrates the effects of the retrospective application on reported balances in DPL’s balance sheet as of December 31, 2014. December 31, 2014 As Filed Reclassification ASC 740 December 31, 2014 As Adjusted (millions of dollars) Deferred income taxes, net (within current assets) $ 16 $ (16 ) $ — Other (within current liabilities) 42 (1 ) 41 Deferred income tax liabilities, net 893 (15 ) 878 |
Segment Information (Tables)
Segment Information (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Segment Reporting [Abstract] | |
Segment Financial Information for Continuing Operations | Segment financial information for continuing operations at and for the years ended December 31, 2015, 2014 and 2013, is as follows: Year Ended December 31, 2015 Power Delivery Pepco Energy Services Corporate and Other (a) PHI Consolidated (millions of dollars) Operating Revenue $ 4,805 $ 223 $ (5 ) $ 5,023 Operating Expenses (b) 4,124 (c) 224 2 4,350 Operating Income (Loss) 681 (1 ) (7 ) 673 Interest Expense 238 — 42 280 Other Income 36 1 17 (d) 54 Income Tax Expense (Benefit) (e) 177 (4 ) (44 ) 129 Net Income from Continuing Operations 302 4 12 318 Total Assets 14,413 221 1,692 16,326 Construction Expenditures $ 1,196 $ 3 $ 31 $ 1,230 (a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to Power Delivery for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit Power Delivery. These expenditures are recorded as incurred in Corporate and Other and are allocated to Power Delivery once the assets are placed in service. Corporate and Other includes intercompany amounts of $(5) million for Operating Revenue, $(4) million for Operating Expenses and $(5) million for Interest Expense. (b) Includes depreciation and amortization expense of $651 million, consisting of $606 million for Power Delivery, $4 million for Pepco Energy Services and $41 million for Corporate and Other. (c) Includes $46 million ($27 million after-tax) related to gains on sales of land at Pepco. (d) Includes $15 million ($10 million after-tax) increase in fair value of preferred stock derivative. (e) Includes tax benefit of $3 million for Power Delivery, $1 million for Pepco Energy Services and $43 million for Corporate and Other associated with the Global Tax Settlement. Year Ended December 31, 2014 Power Delivery Pepco Energy Services Corporate and Other (a) PHI Consolidated (millions of dollars) Operating Revenue $ 4,607 $ 278 $ (7 ) $ 4,878 Operating Expenses (b) 3,916 354 (c) 4 4,274 Operating Income (Loss) 691 (76 ) (11 ) 604 Interest Expense 226 1 41 268 Other Income 40 2 2 44 Income Tax Expense (Benefit) 185 (36 ) (11 ) 138 Net Income (Loss) from Continuing Operations 320 (39 ) (39 ) 242 Total Assets 13,636 249 1,704 15,589 Construction Expenditures $ 1,144 $ 3 $ 76 $ 1,223 (a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to Power Delivery for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit Power Delivery. These expenditures are recorded as incurred in Corporate and Other and are allocated to Power Delivery once the assets are placed in service. Corporate and Other includes intercompany amounts of $(7) million for Operating Revenue, $(7) million for Operating Expenses and $(4) million for Interest Expense. (b) Includes depreciation and amortization expense of $549 million, consisting of $511 million for Power Delivery, $7 million for Pepco Energy Services and $31 million for Corporate and Other. (c) Includes impairment losses of $81 million ($48 million after-tax) associated with Pepco Energy Services’ combined heat and power thermal generating facilities and operations in Atlantic City. Year Ended December 31, 2013 Power Delivery Pepco Energy Services Corporate and Other (a) PHI Consolidated (millions of dollars) Operating Revenue $ 4,472 $ 203 $ (9 ) $ 4,666 Operating Expenses (b) 3,828 201 (c) (31 ) 3,998 Operating Income 644 2 22 668 Interest Expense 228 1 44 273 Other Income 28 3 3 34 Income Tax Expense (d) 155 1 163 (e) 319 Net Income (Loss) from Continuing Operations 289 3 (182 ) 110 Total Assets 12,868 337 1,573 14,778 Construction Expenditures $ 1,194 $ 4 $ 112 $ 1,310 (a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to Power Delivery for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit Power Delivery. These expenditures are recorded as incurred in Corporate and Other and are allocated to Power Delivery once the assets are placed in service. Corporate and Other includes intercompany amounts of $(10) million for Operating Revenue, $(9) million for Operating Expenses and $(5) million for Interest Expense. (b) Includes depreciation and amortization expense of $473 million, consisting of $439 million for Power Delivery, $6 million for Pepco Energy Services and $28 million for Corporate and Other. (c) Includes impairment losses of $4 million ($3 million after-tax) associated with Pepco Energy Services’ landfill gas-fired electric generation facility. (d) Includes after-tax interest associated with uncertain and effectively settled tax positions allocated to each member of the consolidated group, including a $12 million interest benefit for Power Delivery and interest expense of $66 million for Corporate and Other. (e) Includes non-cash charges of $101 million representing the establishment of valuation allowances against certain deferred tax assets of PCI included in Corporate and Other. |
Regulatory Matters (Tables)
Regulatory Matters (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Schedule of Regulatory Assets and Regulatory Liabilities | The components of Pepco Holdings’ regulatory asset and liability balances at December 31, 2015 and 2014 are as follows: 2015 2014 (millions of dollars) Regulatory Assets Pension and other postretirement benefit costs $ 910 $ 946 Demand-side management costs 403 329 Smart Grid costs 266 261 Recoverable income taxes 224 274 Securitized stranded costs 202 278 Incremental storm restoration costs 43 51 Deferred debt extinguishment costs 36 42 Deferred energy supply costs 32 73 Recoverable workers’ compensation and long-term disability costs 31 30 MAPP abandonment costs 7 33 Deferred losses on gas derivatives 2 4 Other 90 88 Total Regulatory Assets $ 2,246 $ 2,409 Regulatory Liabilities Asset removal costs $ 211 $ 250 Reserves for FERC ROE transmission challenges 32 4 Federal and state tax benefits, related to securitized stranded costs 13 8 Deferred income taxes due to customers 12 44 Deferred energy supply costs 11 3 Other 29 34 Total Regulatory Liabilities $ 308 $ 343 |
Atlantic City Electric Co [Member] | |
Schedule of Regulatory Assets and Regulatory Liabilities | The components of ACE’s regulatory asset and liability balances at December 31, 2015 and 2014 are as follows: 2015 2014 (millions of dollars) Regulatory Assets Securitized stranded costs $ 202 $ 278 Recoverable income taxes 44 42 Deferred energy supply costs 27 58 Incremental storm restoration costs 18 15 Deferred debt extinguishment costs 7 8 Other 24 26 Total Regulatory Assets $ 322 $ 427 Regulatory Liabilities Federal and state tax benefits, related to securitized stranded costs $ 13 $ 8 Reserves for FERC ROE transmission challenges 8 1 Deferred income taxes due to customers 3 3 Other 3 2 Total Regulatory Liabilities $ 27 $ 14 |
Potomac Electric Power Co [Member] | |
Schedule of Regulatory Assets and Regulatory Liabilities | The components of Pepco’s regulatory asset and liability balances at December 31, 2015 and 2014 are as follows: 2015 2014 (millions of dollars) Regulatory Assets Demand-side management costs $ 292 $ 238 Smart Grid costs 181 175 Recoverable income taxes 142 148 Recoverable workers’ compensation and long-term disability costs 31 30 Incremental storm restoration costs 19 29 Deferred debt extinguishment costs 19 22 MAPP abandonment costs 4 19 Deferred energy supply costs 3 3 Other 29 33 Total Regulatory Assets $ 720 $ 697 Regulatory Liabilities Asset removal costs $ 58 $ 84 Reserves for FERC ROE transmission challenges 13 2 Deferred income taxes due to customers 6 4 Deferred energy supply costs 5 3 Other 10 11 Total Regulatory Liabilities $ 92 $ 104 |
Delmarva Power & Light Co/De [Member] | |
Schedule of Regulatory Assets and Regulatory Liabilities | The components of DPL’s regulatory asset and liability balances at December 31, 2015 and 2014 are as follows: 2015 2014 (millions of dollars) Regulatory Assets Demand-side management costs $ 111 $ 91 Smart Grid costs 85 86 Recoverable income taxes 38 84 COPCO acquisition adjustment 13 18 Deferred debt extinguishment costs 10 12 Incremental storm restoration costs 6 7 MAPP abandonment costs 3 14 Deferred energy supply costs 2 12 Deferred losses on gas derivatives 2 4 Other 38 28 Total Regulatory Assets $ 308 $ 356 Regulatory Liabilities Asset removal costs $ 153 $ 166 Reserves for FERC ROE transmission challenges 11 1 Deferred energy supply costs 6 — Deferred income taxes due to customers 3 37 Other 16 21 Total Regulatory Liabilities $ 189 $ 225 |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Schedule of Property, Plant and Equipment | Property, plant and equipment is comprised of the following: Original Cost Accumulated Net Book Value (millions of dollars) At December 31, 2015 Generation $ 23 $ 19 $ 4 Distribution 10,051 3,161 6,890 Transmission 3,554 962 2,592 Gas 546 163 383 Construction work in progress 604 — 604 Non-operating and other property 1,440 609 831 Total $ 16,218 $ 4,914 $ 11,304 At December 31, 2014 Generation $ 104 $ 100 $ 4 Distribution 9,527 3,021 6,506 Transmission 3,252 934 2,318 Gas 511 153 358 Construction work in progress 688 — 688 Non-operating and other property 1,383 751 632 Total $ 15,465 $ 4,959 $ 10,506 |
Capital Lease Assets Recorded within Property, Plant and Equipment | Capital lease assets recorded within Property, Plant and Equipment at December 31, 2015 and 2014 are comprised of the following: Original Accumulated Amortization Net Book Value (millions of dollars) At December 31, 2015 Transmission $ 76 $ 51 $ 25 Distribution 76 51 25 Total $ 152 $ 102 $ 50 At December 31, 2014 Transmission $ 76 $ 46 $ 30 Distribution 76 46 30 Total $ 152 $ 92 $ 60 |
Atlantic City Electric Co [Member] | |
Schedule of Property, Plant and Equipment | Property, plant and equipment is comprised of the following: Original Cost Accumulated Net Book Value (millions of dollars) At December 31, 2015 Distribution $ 2,012 $ 472 $ 1,540 Transmission 968 228 740 Construction work in progress 158 — 158 Non-operating and other property 167 64 103 Total $ 3,305 $ 764 $ 2,541 At December 31, 2014 Generation $ 10 $ 9 $ 1 Distribution 1,931 450 1,481 Transmission 839 223 616 Construction work in progress 115 — 115 Non-operating and other property 178 78 100 Total $ 3,073 $ 760 $ 2,313 |
Potomac Electric Power Co [Member] | |
Schedule of Property, Plant and Equipment | Property, plant and equipment is comprised of the following: Original Accumulated Depreciation Net Book (millions of dollars) At December 31, 2015 Distribution $ 5,996 $ 2,199 $ 3,797 Transmission 1,378 475 903 Construction work in progress 318 — 318 Non-operating and other property 399 125 274 Total $ 8,091 $ 2,799 $ 5,292 At December 31, 2014 Distribution $ 5,668 $ 2,082 $ 3,586 Transmission 1,306 463 843 Construction work in progress 312 — 312 Non-operating and other property 478 271 207 Total $ 7,764 $ 2,816 $ 4,948 |
Capital Lease Assets Recorded within Property, Plant and Equipment | Capital lease assets recorded within Property, plant and equipment at December 31, 2015 and 2014 are comprised of the following: Original Accumulated Amortization Net Book (millions of dollars) At December 31, 2015 Transmission $ 76 $ 51 $ 25 Distribution 76 51 25 Total $ 152 $ 102 $ 50 At December 31, 2014 Transmission $ 76 $ 46 $ 30 Distribution 76 46 30 Total $ 152 $ 92 $ 60 |
Delmarva Power & Light Co/De [Member] | |
Schedule of Property, Plant and Equipment | Property, plant and equipment is comprised of the following: Original Cost Accumulated Depreciation Net Book Value (millions of dollars) At December 31, 2015 Distribution $ 2,043 $ 490 $ 1,553 Transmission 1,208 259 949 Gas 546 163 383 Construction work in progress 107 — 107 Non-operating and other property 305 134 171 Total $ 4,209 $ 1,046 $ 3,163 At December 31, 2014 Distribution $ 1,928 $ 489 $ 1,439 Transmission 1,107 248 859 Gas 511 153 358 Construction work in progress 125 — 125 Non-operating and other property 275 131 144 Total $ 3,946 $ 1,021 $ 2,925 |
Pension and Other Postretirem39
Pension and Other Postretirement Benefits (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Schedule of Changes in Benefit Obligations and Plan Assets | The following table shows changes in the benefit obligation and plan assets for the years ended December 31, 2015 and 2014: Pension Benefits Other Postretirement 2015 2014 2015 2014 (millions of dollars) Change in Benefit Obligation Benefit obligation as of January 1 $ 2,638 $ 2,238 $ 632 $ 574 Service cost 57 44 7 7 Interest cost 109 109 24 26 Actuarial loss (gain) (151 ) 401 (61 ) 59 Benefits paid (163 ) (154 ) (39 ) (34 ) Benefit obligation as of December 31 $ 2,490 $ 2,638 $ 563 $ 632 Change in Plan Assets Fair value of plan assets as of January 1 $ 2,236 $ 2,116 $ 367 $ 368 Actual return on plan assets (61 ) 268 1 21 Company and participant contributions 6 6 5 6 Benefits paid by plan (163 ) (154 ) (25 ) (28 ) Fair value of plan assets as of December 31 $ 2,018 $ 2,236 $ 348 $ 367 Funded Status at end of year (plan assets less plan obligations) $ (472 ) $ (402 ) $ (215 ) $ (265 ) |
Amounts Recognized in Consolidated Balance Sheets | The following table provides the amounts recorded in PHI’s consolidated balance sheets as of December 31, 2015 and 2014: Pension Benefits Other Postretirement 2015 2014 2015 2014 (millions of dollars) Regulatory asset $ 870 $ 871 $ 40 $ 75 Current liabilities (6 ) (6 ) — — Pension benefit obligation (466 ) (396 ) — — Other postretirement benefit obligations — — (215 ) (265 ) Deferred income tax liabilities (162 ) (193 ) 70 77 Accumulated other comprehensive loss, net of tax 28 37 — — Net amount recorded $ 264 $ 313 $ (105 ) $ (113 ) |
Schedule of Amounts Included in AOCL and Regulatory Assets | Amounts included in AOCL (pre-tax) and Regulatory assets at December 31, 2015 and 2014 consist of: Pension Other Postretirement 2015 2014 2015 2014 (millions of dollars) Unrecognized net actuarial loss $ 910 $ 925 $ 128 $ 176 Unamortized prior service cost (credit) 6 8 (88 ) (101 ) Total $ 916 $ 933 $ 40 $ 75 Accumulated other comprehensive loss ($28 million and $37 million, net of tax, at December 31, 2015 and 2014, respectively) $ 46 $ 62 $ — $ — Regulatory assets 870 871 40 75 Total $ 916 $ 933 $ 40 $ 75 |
Summary of Changes in Plan Assets and Benefit Obligations Recognized in AOCL and Regulatory Assets | The table below provides the changes in plan assets and benefit obligations recognized in AOCL and Regulatory assets for the years ended December 31, 2015, 2014 and 2013: Pension Benefits Other Postretirement 2015 2014 2013 2015 2014 2013 (millions of dollars) Amounts amortized during the year: Amortization of prior service (cost) credit $ (2 ) $ (2 ) $ (2 ) $ 13 $ 13 $ 11 Amortization of net actuarial loss (65 ) (45 ) (67 ) (8 ) (3 ) (12 ) Amounts arising during the year: Current year prior service cost (credit) — — 3 — — (124 ) Current year actuarial loss (gain) 50 276 (218 ) (39 ) 62 (109 ) Total recognized in AOCL and Regulatory assets for the year ended December 31 $ (17 ) $ 229 $ (284 ) $ (34 ) $ 72 $ (234 ) |
Components of Net Periodic Benefit Costs | The table below provides the components of net periodic benefit costs recognized for the years ended December 31, 2015, 2014 and 2013: Pension Benefits Other Postretirement 2015 2014 2013 2015 2014 2013 (millions of dollars) Service cost $ 57 $ 44 $ 53 $ 7 $ 7 $ 8 Interest cost 109 109 100 24 26 29 Expected return on plan assets (140 ) (141 ) (145 ) (22 ) (24 ) (20 ) Amortization of prior service cost (credit) 2 2 2 (13 ) (13 ) (11 ) Amortization of net actuarial loss 65 45 67 8 3 12 Net periodic benefit cost $ 93 $ 59 $ 77 $ 4 $ (1 ) $ 18 |
Split of Combined Pension and Other Postretirement Net Periodic Benefit Costs | The table below provides the split of the combined pension and other postretirement net periodic benefit costs among subsidiaries for the years ended December 31, 2015, 2014 and 2013: 2015 2014 2013 (millions of dollars) Pepco $ 30 $ 22 $ 34 DPL 15 7 18 ACE 15 13 17 Other subsidiaries 37 16 26 Total $ 97 $ 58 $ 95 |
Weighted Average Assumptions Used to Determine Benefit Obligations | The following weighted average assumptions were used to determine the benefit obligations at December 31, 2015 and 2014: Pension Benefits Other Postretirement 2015 2014 2015 2014 Discount rate 4.65% /4.55 % (a) 4.20 % 4.55 % 4.15 % Rate of compensation increase 5.00 % 5.00 % 5.00 % 5.00 % Health care cost trend rate assumed for current year – pre 65 — — 6.33 % 6.67 % Health care cost trend rate assumed for current year – post 65 — — 5.40 % 5.50 % Rate to which the cost trend rate is assumed to decline for all eligible retirees (the ultimate trend rate) — — 5.00 % 5.00 % Year that the cost trend rate reaches the ultimate trend rate — — 2020 2020 (a) The discount rate for the qualified and nonqualified pension plans was 4.65% and 4.55%, respectively. |
Summary of Effect of One Percent Change in Assumed Health Care Cost | A one-percentage-point change in assumed health care cost trend rates would have the following effects, in millions of dollars: 1-Percentage- Point Increase 1-Percentage- Point Decrease Increase (decrease) in total service and interest cost $ 1 $ (1 ) Increase (decrease) in postretirement benefit obligation $ 15 $ (18 ) |
Weighted Average Assumptions Used to Determine Net Periodic Benefit Costs | The following weighted average assumptions were used to determine the net periodic benefit cost for the years ended December 31, 2015, 2014 and 2013: Pension Benefits Other Postretirement Benefits 2015 2014 2013 2015 2014 2013 Discount rate 4.20 % 5.05 % 4.15 % 4.15 % 5.00 % 4.10%/4.95 % (a) Expected long-term return on plan assets 6.50 % 7.00 % 7.00 % 6.75 % 7.25 % 7.00 % Rate of compensation increase 5.00 % 5.00 % 5.00 % 5.00 % 5.00 % 5.00 % Health care cost trend rate — — — 6.67 % 7.00 % 7.50 % (a) The discount rate was updated for remeasurement to 4.95% on July 1, 2013. |
Schedule of Fair Value of Plan Assets | The following tables present the fair values of PHI’s pension and other postretirement benefit plan assets by asset category included in and excluded from the fair value hierarchy levels, as of December 31, 2015 and 2014: Fair Value Measurements at December 31, 2015 Total Quoted Prices Significant (Level 2) Significant (Level 3) (millions of dollars) Asset Category Pension Plan Assets: Equity: Domestic (a) $ 311 $ 120 $ 191 $ — International (b) 216 215 — 1 Fixed Income (c) 820 — 810 10 Cash Equivalents (d) 50 50 — — 1,397 $ 385 $ 1,001 $ 11 Investments measured at fair value using net asset value as a practical expedient: Equity: Domestic (a) 33 Fixed Income (c) 504 Other: Private Equity 38 Real Estate 46 Pension Plan Assets Total $ 2,018 Other Postretirement Plan Assets: Equity (e) $ 197 $ 197 $ — $ — Fixed Income (f) 120 120 — — Cash Equivalents 9 9 — — 326 $ 326 $ — $ — Investments measured at fair value using net asset value as a practical expedient: Equity (e) 22 Postretirement Plan Assets Total $ 348 (a) Domestic equity assets predominantly include domestic common stock and commingled funds. (b) International equity assets predominantly include foreign common and preferred stock and warrants. (c) Fixed income assets predominantly include corporate bonds, government bonds, municipal/provincial bonds, collateralized mortgage obligations and commingled funds. (d) Cash equivalents predominantly include cash investments in short-term investment funds. (e) Equity assets include domestic and international commingled funds. (f) Fixed income assets include fixed income commingled funds. Fair Value Measurements at December 31, 2014 Total Quoted Prices Significant (Level 2) Significant (Level 3) (millions of dollars) Asset Category Pension Plan Assets: Equity: Domestic (a) $ 341 $ 128 $ 213 $ — International (b) 255 254 — 1 Fixed Income (c) 916 — 905 11 Cash Equivalents (d) 45 45 — — 1,557 $ 427 $ 1,118 $ 12 Investments measured at fair value using net asset value as a practical expedient: Equity: Domestic (a) 35 Fixed Income (c) 543 Other: Private Equity 47 Real Estate 54 Pension Plan Assets Total $ 2,236 Other Postretirement Plan Assets: Equity (e) $ 208 $ 208 $ — $ — Fixed Income (f) 126 126 — — Cash Equivalents 6 6 — — 340 $ 340 $ — $ — Investments measured at fair value using net asset value as a practical expedient: Equity (e) 27 Postretirement Plan Assets Total $ 367 (a) Domestic equity assets predominantly include domestic common stock and commingled funds. (b) International equity assets predominantly include foreign common and preferred stock and warrants. (c) Fixed income assets predominantly include corporate bonds, government bonds, municipal/provincial bonds, collateralized mortgage obligations and commingled funds. (d) Cash equivalents predominantly include cash investments in short-term investment funds. (e) Equity assets include domestic and international commingled funds. (f) Fixed income assets include fixed income commingled funds. |
Reconciliation of Fair Value Measurements Using Significant Unobservable Inputs | Reconciliations of the beginning and ending balances of PHI’s fair value measurements using significant unobservable inputs (level 3) for investments in the pension plan for the years ended December 31, 2015 and 2014 are shown below: Fair Value Measurements Using Significant Unobservable Inputs (Level 3) Equity Fixed Income Total Level 3 (millions of dollars) Balance as of January 1, 2015 $ 1 $ 11 $ 12 Transfer in (out) of Level 3 — — — Purchases — — — Sales — — — Settlements — (1 ) (1 ) Unrealized gain (loss) — — — Realized gain — — — Balance as of December 31, 2015 $ 1 $ 10 $ 11 Fair Value Measurements Using Significant Unobservable Inputs (Level 3) Equity Fixed Income Total Level 3 (millions of dollars) Balance as of January 1, 2014 $ 1 $ 11 $ 12 Transfer in (out) of Level 3 — — — Purchases — — — Sales — — — Settlements — — — Unrealized gain (loss) — — — Realized gain — — — Balance as of December 31, 2014 $ 1 $ 11 $ 12 |
Schedule of Estimated Benefit Payments | Estimated future benefit payments to participants in PHI’s pension and other postretirement benefit plans, which reflect expected future service as appropriate, are as follows: Years Pension Benefits Other Postretirement (millions of dollars) 2016 $ 143 $ 38 2017 143 38 2018 148 38 2019 153 38 2020 158 38 2021 through 2025 836 189 |
Pension Benefits [Member] | |
Summary of Plan Asset Allocations | The PHI Retirement Plan asset allocations at December 31, 2015 and 2014, by asset category, were as follows: Asset Category Plan Assets at December 31, Target Plan Asset Allocation 2015 2014 2015 2014 Equity 28 % 28 % 27 % 27 % Fixed Income 66 % 65 % 68 % 68 % Other (real estate, private equity) 6 % 7 % 5 % 5 % Total 100 % 100 % 100 % 100 % |
Other Postretirement Benefits [Member] | |
Summary of Plan Asset Allocations | PHI’s other postretirement benefit plan asset allocations at December 31, 2015 and 2014, by asset category, were as follows: Asset Category Plan Assets at December 31, Target Plan Asset Allocation 2015 2014 2015 2014 Equity 63 % 64 % 60 % 60 % Fixed Income 34 % 34 % 35 % 35 % Cash 3 % 2 % 5 % 5 % Total 100 % 100 % 100 % 100 % |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Components of Long-Term Debt | The components of long-term debt are shown in the table below: At December 31, Interest Rate Maturity 2015 2014 (millions of dollars) First Mortgage Bonds Pepco: 3.05% 2022 $ 200 $ 200 6.20% (a)(b) 2022 110 110 3.60% 2024 400 400 5.75% (c)(d) 2034 100 100 5.40% (c)(d) 2035 175 175 6.50% (a)(c) 2037 500 500 7.90% 2038 250 250 4.15% 2043 450 250 4.95% 2043 150 150 ACE: 7.68% (e) 2015 - 2016 2 17 7.75% 2018 250 250 6.80% (d)(f) 2021 39 39 4.35% 2021 200 200 3.375% 2024 150 150 3.50% 2025 150 — 4.875% (a)(f) 2029 23 23 5.80% (d)(g) 2034 120 120 5.80% (d)(g) 2036 105 105 DPL: 5.22% (h) 2016 100 100 3.50% 2023 500 500 4.00% 2042 250 250 4.15% 2045 200 — Total First Mortgage Bonds 4,424 3,889 Unsecured Tax-Exempt Bonds DPL: 5.40% 2031 78 78 Total Unsecured Tax-Exempt Bonds 78 78 NOTE: Schedule is continued on next page. At December 31, Interest Rate Maturity 2015 2014 (millions of dollars) Medium-Term Notes (unsecured) DPL: 7.56% - 7.58% 2017 $ 14 $ 14 6.81% 2018 4 4 7.61% 2019 12 12 7.72% 2027 10 10 Total Medium-Term Notes (unsecured) 40 40 Notes (secured) Pepco Energy Services: 6.70% - 7.46% 2015-2018 3 4 Notes (unsecured) PHI: 2.70% 2015 — 250 5.90% 2016 190 190 6.125% 2017 81 81 7.45% 2032 185 185 DPL: 5.00% 2015 — 100 Total Notes (unsecured) 456 806 Total Long-Term Debt 5,001 4,817 Net unamortized discount (2 ) (10 ) Unamortized debt issuance costs (49 ) (44 ) Current portion of long-term debt (294 ) (366 ) Total Net Long-Term Debt $ 4,656 $ 4,397 (a) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for the issuer’s obligations under the corresponding series of issuer notes or tax-exempt bonds, at such time as the issuer does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds), except that the issuer may not permit such release of collateral unless the issuer substitutes comparable obligations for such collateral. (b) Represents a series of Collateral First Mortgage Bonds securing a series of senior notes issued by Pepco, which in turn secures a series of tax-exempt bonds issued for the benefit of Pepco. (c) Represents a series of Collateral First Mortgage Bonds (as defined herein) securing a series of senior notes issued by Pepco. (d) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for the issuer’s obligations under the corresponding series of issuer notes (as defined herein) or tax-exempt bonds, at such time as the issuer does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds). (e) Represents a series of Collateral First Mortgage Bonds securing a series of medium-term notes issued by ACE. (f) Represents a series of Collateral First Mortgage Bonds securing a series of tax-exempt bonds issued for the benefit of ACE. (g) Represents a series of Collateral First Mortgage Bonds securing a series of senior notes issued by ACE. (h) Represents a series of Collateral First Mortgage Bonds securing a series of debt securities issued by DPL. The outstanding first mortgage bonds issued by each of Pepco, DPL and ACE are issued under a mortgage and deed of trust and are secured by a first lien on substantially all of the issuing company’s property, plant and equipment, except for certain property excluded from the lien of the respective mortgage. PHI’s long-term debt is subject to certain covenants. As of December 31, 2015, PHI and its subsidiaries were in compliance with all such covenants. The table above does not separately identify $885 million, $100 million and $227 million in aggregate principal amount of senior notes, medium term notes and other debt securities (issuer notes) issued by each of Pepco, DPL and ACE, respectively, and $110 million and $62 million in aggregate principal amount of tax-exempt bonds issued for the benefit of Pepco and ACE, respectively. These issuer notes are secured by a like amount of first mortgage bonds (Collateral First Mortgage Bonds) of each respective issuer. In addition, these tax-exempt bonds are secured by a like amount of Collateral First Mortgage Bonds issued by the utility subsidiary for whose benefit the tax-exempt bonds were issued. The principal terms of each such series of issuer notes, or the issuer’s obligations in respect of each such series of tax-exempt bonds, are identical to the same terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest made on a series of such issuer notes, or the satisfaction of the issuer’s obligations in respect of a series of such tax-exempt bonds, satisfy the corresponding obligations on the related series of Collateral First Mortgage Bonds. For these reasons, each such series of Collateral First Mortgage Bonds and the corresponding issuer notes and/or tax-exempt bonds together effectively represent a single financial obligation and are not identified in the table above separately. Bond Issuances During 2015, Pepco issued $200 million of 4.15% first mortgage bonds due March 15, 2043, with a 3.9% yield to maturity. Net proceeds from the issuance of the bonds, which included a premium of $8 million, were used by Pepco to repay outstanding commercial paper and for general corporate purposes. During 2015, DPL issued $200 million of 4.15% first mortgage bonds due May 15, 2045. Net proceeds from the issuance of the bonds were used by DPL to repay outstanding commercial paper and for general corporate purposes. During 2015, ACE issued $150 million of 3.50% first mortgage bonds due December 1, 2025 in a private placement. The net proceeds from the issuance of the bonds were used by ACE to repay outstanding commercial paper and for general corporate purposes. Note Retirements During 2015, ACE retired, at maturity, $15 million of its secured medium-term notes series C. The medium-term notes were secured by a like principal amount of its 7.68% first mortgage bonds due August 24, 2015, which under the mortgage and deed of trust were deemed to be satisfied when the medium-term notes were repaid. During 2015, DPL retired, at maturity, $100 million of its 5.00% unsecured notes due June 1, 2015. During 2015, PHI retired, at maturity, $250 million of its 2.70% unsecured notes due October 1, 2015. Transition Bonds Issued by ACE Funding The components of transition bonds are shown in the table below: At December 31, Interest Rate Maturity 2015 2014 (millions of dollars) 4.91% 2017 $ — $ 17 5.05% 2020 39 51 5.55% 2023 132 147 Total Transition Bonds 171 215 Unamortized debt issuance costs (1 ) (1 ) Current portion of long-term debt (46 ) (44 ) Total Net Long-Term Transition Bonds $ 124 $ 170 |
Components of Short-Term Debt | The components of PHI’s short-term debt at December 31, 2015 and 2014 are as follows: 2015 2014 (millions of dollars) Commercial paper $ 658 $ 624 Variable rate demand bonds 105 105 Term loan 300 — Total $ 1,063 $ 729 |
Atlantic City Electric Co [Member] | |
Components of Long-Term Debt | The components of long-term debt are shown in the table below: Type of Debt Interest Rate Maturity 2015 2014 (millions of dollars) First Mortgage Bonds 7.68 % (a) 2015-2016 $ 2 $ 17 7.75 % 2018 250 250 6.80 % (b)(c) 2021 39 39 4.35 % 2021 200 200 3.375 % 2024 150 150 3.50 % 2025 150 — 4.875 %(c)(d) 2029 23 23 5.80 % (b)(e) 2034 120 120 5.80 % (b)(e) 2036 105 105 Total long-term debt 1,039 904 Net unamortized discount (1 ) (1 ) Unamortized debt issuance costs (6 ) (6 ) Current portion of long-term debt (2 ) (15 ) Total net long-term debt $ 1,030 $ 882 (a) Represents a series of Collateral First Mortgage Bonds (as defined herein) securing a series of medium-term notes issued by ACE. (b) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for ACE’s obligations under the corresponding series of issuer notes (as defined herein) or tax-exempt bonds, at such time as ACE does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds). (c) Represents a series of Collateral First Mortgage Bonds securing a series of tax-exempt bonds issued for the benefit of ACE. (d) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for ACE’s obligations under the corresponding series of issuer notes or tax-exempt bonds, at such time as ACE does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds), except that ACE may not permit such release of collateral unless ACE substitutes comparable obligations for such collateral. (e) Represents a series of Collateral First Mortgage Bonds securing a series of senior notes issued by ACE. The outstanding first mortgage bonds issued by ACE are issued under a mortgage and deed of trust and are secured by a first lien on substantially all of ACE’s property, plant and equipment, except for certain property excluded from the lien of the mortgage. Maturities of ACE’s long-term debt outstanding at December 31, 2015 are $2 million in 2016, zero in 2017, $250 million in 2018, zero in 2019 and 2020, and $787 million thereafter. ACE’s long-term debt is subject to certain covenants. As of December 31, 2015, ACE was in compliance with all such covenants. The table above does not separately identify $227 million in aggregate principal amount of senior notes and medium term notes (issuer notes) issued by ACE and $62 million in aggregate principal amount of tax-exempt bonds issued for the benefit of ACE. These issuer notes and tax-exempt bonds are secured by a like amount of first mortgage bonds (Collateral First Mortgage Bonds) of ACE. The principal terms of each such series of issuer notes, or ACE’s obligations in respect of each such series of tax-exempt bonds, are identical to the same terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest made on a series of such issuer notes, or the satisfaction of ACE obligations in respect of a series of such tax-exempt bonds, satisfy the corresponding obligations on the related series of Collateral First Mortgage Bonds. For these reasons, each such series of Collateral First Mortgage Bonds and the corresponding issuer notes or tax-exempt bonds together effectively represent a single financial obligation and are not identified in the table above separately. Bond Issuance During 2015, ACE issued $150 million of 3.50% first mortgage bonds due December 1, 2025 in a private placement. The net proceeds from the issuance of the bonds were used by ACE to repay outstanding commercial paper and for general corporate purposes. Bond Retirement During 2015, ACE retired, at maturity, $15 million of its secured medium-term notes series C. The medium-term notes were secured by a like principal amount of its 7.68% first mortgage bonds due August 24, 2015, which under the mortgage and deed of trust were deemed to be satisfied when the medium-term notes were repaid. Transition Bonds Issued by ACE Funding The components of transition bonds are shown in the table below: Type of Debt Interest Rate Maturity 2015 2014 (millions of dollars) Transition Bonds 4.91 % 2017 $ — $ 17 5.05 % 2020 39 51 5.55 % 2023 132 147 171 215 Unamortized debt issuance costs (1 ) (1 ) Current portion of long-term debt (46 ) (44 ) Total net long-term Transition Bonds $ 124 $ 170 |
Components of Short-Term Debt | The components of ACE’s short-term debt at December 31, 2015 and 2014 are as follows: 2015 2014 (millions of dollars) Commercial paper $ 5 $ 127 |
Potomac Electric Power Co [Member] | |
Components of Long-Term Debt | The components of long-term debt are shown in the table below: Type of Debt Interest Rate Maturity 2015 2014 (millions of dollars) First Mortgage Bonds 3.05 % 2022 $ 200 $ 200 6.20 %(a)(b) 2022 110 110 3.60 % 2024 400 400 5.75 %(c)(d) 2034 100 100 5.40 %(c)(d) 2035 175 175 6.50 %(a)(c) 2037 500 500 7.90 % 2038 250 250 4.15 % 2043 450 250 4.95 % 2043 150 150 Total long-term debt 2,335 2,135 Net unamortized discount (3 ) (11 ) Unamortized debt issuance costs (31 ) (28 ) Total net long-term debt $ 2,301 $ 2,096 (a) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for Pepco’s obligations under the corresponding series of senior notes or tax-exempt bonds, at such time as Pepco does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds), except that Pepco may not permit such release of collateral unless Pepco substitutes comparable obligations for such collateral. (b) Represents a series of Collateral First Mortgage Bonds securing a series of senior notes issued by Pepco, which in turn secures a series of tax-exempt bonds issued for the benefit of Pepco. (c) Represents a series of Collateral First Mortgage Bonds (as defined herein) securing a series of senior notes issued by Pepco. (d) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for Pepco’s obligations under the corresponding series of senior notes or tax-exempt bonds, at such time as Pepco does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds). |
Components of Short-Term Debt | Pepco’s short-term debt at December 31, 2015 and 2014 consisted of the following: 2015 2014 (millions of dollars) Commercial paper $ 64 $ 104 |
Delmarva Power & Light Co/De [Member] | |
Components of Long-Term Debt | Long-Term Debt The components of long-term debt are shown in the table below: Type of Debt Interest Rate Maturity 2015 2014 (millions of dollars) First Mortgage Bonds 5.22%(a) 2016 $ 100 $ 100 3.50% 2023 500 500 4.00% 2042 250 250 4.15% 2045 200 — 1,050 850 Unsecured Tax-Exempt Bonds 5.40% 2031 78 78 78 78 Medium-Term Notes (unsecured) 7.56%-7.58% 2017 14 14 6.81% 2018 4 4 7.61% 2019 12 12 7.72% 2027 10 10 40 40 Notes (unsecured) 5.00% 2015 — 100 — 100 Total long-term debt 1,168 1,068 Net unamortized premium 2 3 Unamortized debt issuance costs (9 ) (8 ) Current portion of long-term debt (100 ) (100 ) Total net long-term debt $ 1,061 $ 963 (a) Represents a series of Collateral First Mortgage Bonds securing a series of debt securities issued by DPL. |
Components of Short-Term Debt | The components of DPL’s short-term debt at December 31, 2015 and 2014 are as follows: 2015 2014 (millions of dollars) Commercial paper $ 105 $ 106 Variable rate demand bonds 105 105 Total $ 210 $ 211 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Provision for Consolidated Income Taxes from Continuing Operations | Provision for Consolidated Income Taxes – Continuing Operations For the Year Ended December 31, 2015 2014 2013 (millions of dollars) Current Tax (Benefit) Expense Federal $ (3 ) $ (137 ) $ (128 ) State and local 12 (26 ) (9 ) Total Current Tax Expense (Benefit) 9 (163 ) (137 ) Deferred Tax Expense (Benefit) Federal 92 261 393 State and local 30 41 65 Investment tax credit amortization (2 ) (1 ) (2 ) Total Deferred Tax Expense 120 301 456 Total Consolidated Income Tax Expense Related to Continuing Operations $ 129 $ 138 $ 319 |
Reconciliation of Consolidated Income Tax Expense from Continuing Operations | Reconciliation of Consolidated Income Tax Expense – Continuing Operations For the Year Ended December 31, 2015 2014 2013 (millions of dollars) Income tax at Federal statutory rate $ 156 35.0 % $ 133 35.0 % $ 150 35.0 % Increases (decreases) resulting from: State income taxes, net of federal effect 27 6.0 % 23 6.1 % 27 6.3 % Asset removal costs (14 ) (3.1 )% (12 ) (3.2 )% (14 ) (3.3 )% Change in estimates and interest related to uncertain and effectively settled tax positions (46 ) (10.3 )% — — 56 13.1 % Deferred tax basis adjustments 7 1.6 % — — — — Establishment of valuation allowances related to deferred tax assets — — — — 101 23.5 % Merger related costs 4 0.9 % 7 1.8 % — — Other, net (5 ) (1.2 )% (13 ) (3.4 )% (1 ) (0.2 )% Consolidated Income Tax Expense Related to Continuing Operations $ 129 28.9 % $ 138 36.3 % $ 319 74.4 % |
Components of Consolidated Deferred Income Tax Liabilities (Assets) | Components of Consolidated Deferred Tax Liabilities (Assets) At December 31, 2015 2014 (millions of dollars) Deferred Tax Liabilities (Assets) Depreciation and other basis differences related to plant and equipment $ 3,273 $ 2,962 Deferred electric service and electric restructuring liabilities 43 67 Federal and state net operating losses (446 ) (400 ) Valuation allowances on state net operating losses 63 61 Pension and other postretirement benefits 92 116 Deferred taxes on amounts to be collected through future rates 86 94 Other 267 325 Total Deferred Tax Liabilities, net 3,378 3,225 Deferred tax assets included in Other Assets 15 17 Total Consolidated Deferred Tax Liabilities, net $ 3,393 $ 3,242 |
Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits | Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits 2015 2014 2013 (millions of dollars) Balance as of January 1, $ 850 $ 831 $ 200 Tax positions related to current year: Additions — 4 3 Reductions — (2 ) — Tax positions related to prior years: Additions 13 27 646 (b) Reductions (201 )(a) (10 ) (12 ) Settlements (628 )(a) — (6 ) Balance as of December 31, $ 34 $ 850 $ 831 (a) Reductions and settlements in 2015 resulted from the Global Tax Settlement. Settlements represent unrecognized tax benefits that were satisfied with cash or use of net operating losses and tax credits. The majority of the settlements were associated with the treatment of the former cross-border energy lease investments of PCI. (b) These additions of unrecognized tax benefits in 2013 primarily relate to the former cross-border energy lease investments of PCI. |
Other Taxes | 2015 2014 2013 (millions of dollars) Gross Receipts/Delivery $ 124 $ 123 $ 133 Property 92 84 77 County Fuel and Energy 143 143 153 Environmental, Use and Other 68 63 65 Total $ 427 $ 413 $ 428 |
Atlantic City Electric Co [Member] | |
Provision for Consolidated Income Taxes from Continuing Operations | Provision for Consolidated Income Taxes For the Year Ended December 31, 2015 2014 2013 (millions of dollars) Current Tax (Benefit) Expense Federal $ (2 ) $ (7 ) $ (23 ) State and local 3 (2 ) (10 ) Total Current Tax Benefit 1 (9 ) (33 ) Deferred Tax Expense (Benefit) Federal 25 30 28 State and local 5 7 25 Investment tax credit amortization — — (1 ) Total Deferred Tax Expense 30 37 52 Total Consolidated Income Tax Expense $ 31 $ 28 $ 19 |
Reconciliation of Consolidated Income Tax Expense from Continuing Operations | Reconciliation of Consolidated Income Tax Expense For the Year Ended December 31, 2015 2014 2013 (millions of dollars) Income tax at Federal statutory rate $ 24 35.0 % $ 26 35.0 % $ 24 35.0 % Increases (decreases) resulting from: State income taxes, net of federal effect 4 5.8 % 4 5.5 % 5 7.2 % Change in estimates and interest related to uncertain and effectively settled tax positions 3 4.3 % (1 ) (1.4 )% (9 ) (13.0 )% Deferred tax basis adjustments 2 2.9 % — — (2 ) (2.9 )% Investment tax credit amortization — — — — (1 ) (1.4 )% Other, net (2 ) (3.1 )% (1 ) (0.7 )% 2 2.6 % Consolidated Income Tax Expense $ 31 44.9 % $ 28 38.4 % $ 19 27.5 % |
Components of Consolidated Deferred Income Tax Liabilities (Assets) | Components of Consolidated Deferred Income Tax Liabilities (Assets) As of December 31, 2015 2014 (millions of dollars) Deferred Tax Liabilities (Assets) Depreciation and other basis differences related to plant and equipment $ 773 $ 691 Deferred taxes on amounts to be collected through future rates 17 16 Payment for termination of purchased power contracts with NUGs 34 38 Deferred electric service and electric restructuring liabilities 47 71 Pension and other postretirement benefits 20 25 Federal and state net operating losses (9 ) (26 ) Other 6 40 Total Consolidated Deferred Tax Liabilities, net $ 888 $ 855 |
Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits | Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits 2015 2014 2013 (millions of dollars) Balance as of January 1 $ 13 $ 9 $ 17 Tax positions related to current year: Additions — 1 2 Reductions — — — Tax positions related to prior years: Additions — 5 1 Reductions (10 )(a) (2 ) (5 ) Settlements (3 )(a) — (6 ) Balance as of December 31 $ — $ 13 $ 9 (a) Reductions and settlements in 2015 resulted from the Global Tax Settlement. Settlements represent unrecognized tax benefits that were satisfied with cash or use of net operating losses and tax credits. |
Other Taxes | These amounts are recoverable through rates. 2015 2014 2013 (millions of dollars) Gross Receipts/Delivery $ — $ — $ 10 Property 4 3 3 Environmental, Use and Other 1 (1 ) 1 Total $ 5 $ 2 $ 14 |
Potomac Electric Power Co [Member] | |
Provision for Consolidated Income Taxes from Continuing Operations | Provision for Income Taxes For the Year Ended December 31, 2015 2014 2013 (millions of dollars) Current Tax Benefit Federal $ (57 ) $ (79 ) $ (39 ) State and local 6 (3 ) (1 ) Total Current Tax Benefit (51 ) (82 ) (40 ) Deferred Tax Expense (Benefit) Federal 125 150 96 State and local 24 24 24 Investment tax credit amortization — — (1 ) Total Deferred Tax Expense 149 174 119 Total Income Tax Expense $ 98 $ 92 $ 79 |
Reconciliation of Consolidated Income Tax Expense from Continuing Operations | Reconciliation of Income Tax Expense For the Year Ended December 31, 2015 2014 2013 (millions of dollars) Income tax at Federal statutory rate $ 100 35.0 % $ 92 35.0 % $ 80 35.0 % Increases (decreases) resulting from: State income taxes, net of federal effect 15 5.3 % 15 5.7 % 13 5.7 % Asset removal costs (14 ) (4.9 )% (12 ) (4.6 )% (14 ) (6.1 )% Change in estimates and interest related to uncertain and effectively settled tax positions (6 ) (2.1 )% (1 ) (0.4 )% (3 ) (1.3 )% Deferred tax basis adjustments 6 2.1 % — — — — Other, net (3 ) (1.0 )% (2 ) (0.7 )% 3 1.2 % Income Tax Expense $ 98 34.4 % $ 92 35.0 % $ 79 34.5 % |
Components of Consolidated Deferred Income Tax Liabilities (Assets) | Components of Deferred Income Tax Liabilities (Assets) At December 31, 2015 2014 (millions of dollars) Deferred Tax Liabilities (Assets) Depreciation and other basis differences related to plant and equipment $ 1,541 $ 1,423 Pension and other postretirement benefits 95 103 Deferred taxes on amounts to be collected through future rates 55 59 Federal and state net operating losses (141 ) (186 ) Other 171 180 Total Deferred Tax Liabilities, net $ 1,721 $ 1,579 |
Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits | Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits 2015 2014 2013 (millions of dollars) Balance as of January 1 $ 97 $ 101 $ 91 Tax positions related to current year: Additions — 1 1 Reductions — (2 ) — Tax positions related to prior years: Additions 10 1 12 Reductions (55 )(a) (4 ) (3 ) Settlements (40 )(a) — — Balance as of December 31 $ 12 $ 97 $ 101 (a) Reductions and settlements in 2015 resulted from the Global Tax Settlement. Settlements represent unrecognized tax benefits that were satisfied with cash or use of net operating losses and tax credits. |
Other Taxes | Other Taxes Taxes other than income taxes for each year are shown below. These amounts are recoverable through rates. 2015 2014 2013 (millions of dollars) Gross Receipts/Delivery $ 107 $ 107 $ 108 Property 55 51 45 County Fuel and Energy 143 143 153 Environmental, Use and Other 64 62 62 Total $ 369 $ 363 $ 368 |
Delmarva Power & Light Co/De [Member] | |
Provision for Consolidated Income Taxes from Continuing Operations | Provision for Income Taxes For the Year Ended December 31, 2015 2014 2013 (millions of dollars) Current Tax (Benefit) Expense Federal $ (26 ) $ (45 ) $ (8 ) State and local 2 — — Total Current Tax Benefit (24 ) (45 ) (8 ) Deferred Tax Expense (Benefit) Federal 73 99 53 State and local 1 12 12 Investment tax credit amortization (1 ) (1 ) (1 ) Total Deferred Tax Expense 73 110 64 Total Income Tax Expense $ 49 $ 65 $ 56 |
Reconciliation of Consolidated Income Tax Expense from Continuing Operations | Reconciliation of Income Tax Expense For the Year Ended December 31, 2015 2014 2013 (millions of dollars) Income tax at Federal statutory rate $ 44 35.0 % $ 59 35.0 % $ 51 35.0 % Increases (decreases) resulting from: State income taxes, net of federal effect 7 5.6 % 9 5.3 % 8 5.5 % Change in estimates and interest related to uncertain and effectively settled tax positions 3 2.4 % — — (1 ) (0.7 )% Other, net (5 ) (3.8 )% (3 ) (1.8 )% (2 ) (1.2 )% Income Tax Expense $ 49 39.2 % $ 65 38.5 % $ 56 38.6 % |
Components of Consolidated Deferred Income Tax Liabilities (Assets) | Components of Deferred Income Tax Liabilities (Assets) As of December 31, 2015 2014 (millions of dollars) Deferred Tax Liabilities (Assets) Depreciation and other basis differences related to plant and equipment $ 899 $ 797 Deferred taxes on amounts to be collected through future rates 15 19 Federal and state net operating losses (122 ) (115 ) Pension and other postretirement benefits 75 80 Electric restructuring liabilities (4 ) (4 ) Other 78 101 Total Deferred Tax Liabilities, net $ 941 $ 878 |
Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits | Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits 2015 2014 2013 (millions of dollars) Balance as of January 1 $ 22 $ 9 $ 9 Tax positions related to current year: Additions — 1 — Reductions — — — Tax positions related to prior years: Additions 3 13 — Reductions (13 )(a) (1 ) — Settlements (9 )(a) — — Balance as of December 31 $ 3 $ 22 $ 9 (a) Reductions and settlements in 2015 resulted from the Global Tax Settlement. Settlements represent unrecognized tax benefits that were satisfied with cash or use of net operating losses and tax credits. |
Other Taxes | 2015 2014 2013 (millions of dollars) Gross Receipts/Delivery $ 17 $ 16 $ 15 Property 28 24 24 Environmental, Use and Other 2 2 1 Total $ 47 $ 42 $ 40 |
Stock-Based Compensation, Div42
Stock-Based Compensation, Dividend Restrictions, and Calculations of Earnings Per Share of Common Stock (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Schedule of Restricted Stock and Restricted Stock Units | For performance-based restricted stock and restricted stock unit awards, the table reflects awards projected, for purposes of computing the weighted average grant date fair value, to achieve 100% of targeted performance criteria for each outstanding award cycle. Number Weighted Balance as of January 1, 2015 Restricted stock 54,165 $ 26.80 Performance-based restricted stock 70,276 27.01 Time-based restricted stock units 468,958 19.61 Performance-based restricted stock units 827,981 17.73 Total 1,421,380 Granted during 2015 Performance-based restricted stock 48,347 26.10 Time-based restricted stock units 450,203 27.40 Performance-based restricted stock units 6,188 26.08 Total 504,738 Vested during 2015 Performance-based restricted stock (93,906 ) 26.78 Time-based restricted stock units (288,429 ) 20.61 Performance-based restricted stock units (424,705 ) 17.05 Total (807,040 ) Forfeited during 2015 Time-based restricted stock units (2,218 ) 27.00 Performance-based restricted stock units (826 ) 19.33 Total (3,044 ) Balance as of December 31, 2015 Restricted stock 54,165 26.80 Performance-based restricted stock 24,717 26.10 Time-based restricted stock units 628,514 24.71 Performance-based restricted stock units 408,638 18.56 Total 1,116,034 (a) The balance as of December 31, 2015 does not include 36,110 shares of restricted stock, 113,385 time-based restricted stock units and 104,628 performance-based restricted stock units that were vested for executives and 30,784 time-based restricted stock units that were vested for directors but had not yet settled. |
Weighted Average Grant Date Fair Value Per Share | The following table provides the weighted average grant date fair value per share of those awards granted during each of the years ended December 31, 2015, 2014 and 2013: 2015 2014 2013 Weighted average grant-date fair value of each restricted stock award granted during the year $ — $ 26.80 $ — Weighted average grant-date fair value of each performance-based restricted stock award granted during the year $ 26.10 $ 27.01 $ — Weighted average grant-date fair value of each time-based restricted stock unit award granted during the year $ 27.40 $ 19.77 $ 19.70 Weighted average grant-date fair value of each performance-based restricted stock unit award granted during the year $ 26.08 $ 18.53 $ 17.03 |
Dividends Received from Subsidiaries | For the years ended December 31, 2015, 2014 and 2013, dividends paid by PHI’s subsidiaries were as follows: Subsidiary 2015 2014 2013 ( millions of dollars ) Pepco (paid to PHI) $ 146 $ 86 $ 46 DPL (paid to Conectiv) 92 100 30 ACE (paid to Conectiv) 12 26 60 Total $ 250 $ 212 $ 136 |
Calculation of Earnings Per Share of Common Stock | The numerator and denominator for basic and diluted earnings per share of common stock calculations are shown below. For the Year Ended December 31, 2015 2014 2013 (millions of dollars, except per share data) Income (Numerator) Net income from continuing operations $ 318 $ 242 $ 110 Net income (loss) from discontinued operations 9 — (322 ) Net income (loss) $ 327 $ 242 $ (212 ) Shares (Denominator) (in millions): Weighted average shares outstanding for basic computation: Average shares outstanding 253 251 246 Adjustment to shares outstanding — — — Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock 253 251 246 Net effect of potentially dilutive shares (a) 1 1 — Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock 254 252 246 Basic earnings per share of common stock from continuing operations $ 1.25 $ 0.96 $ 0.45 Basic earnings (loss) per share of common stock from discontinued operations 0.04 — (1.31 ) Basic earnings (loss) per share $ 1.29 $ 0.96 $ (0.86 ) Diluted earnings per share of common stock from continuing operations $ 1.25 $ 0.96 $ 0.45 Diluted earnings (loss) per share of common stock from discontinued operations 0.04 — (1.31 ) Diluted earnings (loss) per share $ 1.29 $ 0.96 $ (0.86 ) (a) There were no options to purchase shares of common stock that were excluded from the calculation of diluted earnings per share for the years ended December 31, 2015, 2014 and 2013. |
Common Stock Reserved and Unissued | The following table presents Pepco Holdings’ common stock reserved and unissued at December 31, 2015: Name of Plan Number of DRP 4,584,077 Pepco Holdings Long-Term Incentive Plan (a) 6,946,614 Pepco Holdings 2012 Long-Term Incentive Plan 7,136,961 Pepco Holdings Retirement Savings Plan 3,456,261 Total 22,123,913 (a) No further awards will be made under this plan. |
Derivative Instruments and He43
Derivative Instruments and Hedging Activities (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Fair Values of Derivative Instruments by Balance Sheet Location | The tables below identify the balance sheet location and fair values of derivative instruments as of December 31, 2015 and 2014: As of December 31, 2015 Balance Sheet Caption Derivatives Other Gross Derivative Effects of Net (millions of dollars) Derivative assets (current assets) $ — $ 18 $ 18 $ — $ 18 Derivative liabilities (current liabilities) — (2 ) (2 ) 2 — Net derivative asset $ — $ 16 $ 16 $ 2 $ 18 As of December 31, 2014 Balance Sheet Caption Derivatives Other Gross Derivative Effects of Net (millions of dollars) Derivative assets (current assets) $ — $ 3 $ 3 $ — $ 3 Derivative liabilities (current liabilities) — (4 ) (4 ) 4 — Net derivative (liability) asset $ — $ (1 ) $ (1 ) $ 4 $ 3 |
Schedule of Cash Collateral Offset Against Derivative Positions | The amount of cash collateral that was offset against these derivative positions is as follows: December 31, December 31, (millions of dollars) Cash collateral pledged to counterparties with the right to reclaim (a) $ 2 $ 4 (a) Includes cash deposits on commodity brokerage accounts. |
Cash Flow Hedges Included in Accumulated Other Comprehensive Loss | The data in the following tables indicate the cumulative net loss after-tax related to terminated cash flow hedges by contract type included in AOCL, the portion of AOCL expected to be reclassified to income during the next 12 months, and the maximum hedge or deferral term: Contracts As of December 31, 2015 Maximum Term Accumulated Other Portion Expected to be Reclassified (millions of dollars) Interest rate $ 8 $ 1 200 months Contracts As of December 31, 2014 Maximum Term Accumulated Other Portion Expected (millions of dollars) Interest rate $ 9 $ 1 212 months |
Net Unrealized and Realized Derivative Gains (Losses) Deferred as Regulatory Liabilities and Regulatory Assets | The following table shows the net unrealized and net realized derivative gains and losses arising during the period associated with these derivatives that were recognized in the consolidated statements of income (loss) (through Fuel and purchased energy expense) and that were also deferred as regulatory liabilities and regulatory assets, respectively, for the years ended December 31, 2015, 2014 and 2013: For the Year Ended December 31, 2015 2014 2013 (millions of dollars) Net unrealized (loss) gain arising during the period $ (3 ) $ (3 ) $ 4 Net realized (loss) gain recognized during the period (5 ) 2 (4 ) |
Net Outstanding Commodity Forward Contracts That Did Not Qualify for Hedge Accounting | As of December 31, 2015 and 2014, the quantities and positions of DPL’s net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting were: December 31, 2015 December 31, 2014 Commodity Quantity Net Position Quantity Net Position DPL – Natural gas (one Million British Thermal Units) 4,190,000 Long 3,892,500 Long |
Delmarva Power & Light Co/De [Member] | |
Fair Values of Derivative Instruments by Balance Sheet Location | The tables below identify the balance sheet location and fair values of derivative instruments as of December 31, 2015 and 2014: As of December 31, 2015 Balance Sheet Caption Derivatives Designated as Hedging Instruments Other Derivative Instruments Gross Derivative Instruments Effects of Cash Collateral and Netting Net Derivative Instruments (millions of dollars) Derivative liabilities (current liabilities) $ — $ (2 ) $ (2 ) $ 2 $ — As of December 31, 2014 Balance Sheet Caption Derivatives Designated as Hedging Instruments Other Derivative Instruments Gross Derivative Instruments Effects of Cash Collateral and Netting Net Derivative Instruments (millions of dollars) Derivative liabilities (current liabilities) $ — $ (4 ) $ (4 ) $ 4 $ — |
Schedule of Cash Collateral Offset Against Derivative Positions | The amount of cash collateral that was offset against these derivative positions is as follows: December 31, December 31, (millions of dollars) Cash collateral pledged to counterparties with the right reclaim (a) $ 2 $ 4 (a) Includes cash deposits on commodity brokerage accounts. |
Net Unrealized and Realized Derivative Gains (Losses) Deferred as Regulatory Liabilities and Regulatory Assets | The following table shows the net unrealized and net realized derivative gains and losses arising during the period associated with these derivatives that were recognized in the statements of income (through Purchased energy and Gas purchased expense) and that were also deferred as regulatory liabilities and regulatory assets, respectively, for the years ended December 31, 2015, 2014 and 2013: For the Year Ended December 31, 2015 2014 2013 (millions of dollars) Net unrealized (loss) gain arising during the period $ (3 ) $ (3 ) $ 1 Net realized (loss) gain recognized during the period (5 ) 2 (4 ) |
Net Outstanding Commodity Forward Contracts That Did Not Qualify for Hedge Accounting | As of December 31, 2015 and 2014, the quantities and positions of DPL’s net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting were: December 31, 2015 December 31, 2014 Commodity Quantity Net Position Quantity Net Position Natural Gas (One Million British Thermal Units) 4,190,000 Long 3,892,500 Long |
Fair Value Disclosures (Tables)
Fair Value Disclosures (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value of Financial Assets and Liabilities Measured on Recurring Basis | The following tables set forth, by level within the fair value hierarchy, PHI’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. PHI’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. Fair Value Measurements at December 31, 2015 Description Total Quoted Prices in Significant Significant (millions of dollars) ASSETS Derivative instruments Preferred stock $ 18 $ — $ — $ 18 Cash equivalents and restricted cash equivalents Treasury fund 42 42 — — Executive deferred compensation plan assets Money market funds and short-term investments 27 12 15 — Life insurance contracts 46 — 27 19 Total $ 133 $ 54 $ 42 $ 37 LIABILITIES Derivative instruments (b) Natural gas (c) $ 2 $ 2 $ — $ — Executive deferred compensation plan liabilities Life insurance contracts 30 — 30 — Total $ 32 $ 2 $ 30 $ — (a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2015. (b) The fair values of derivative liabilities reflect netting by counterparty before the impact of collateral. (c) Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC. Fair Value Measurements at December 31, 2014 Description Total Quoted Prices in Significant Significant (millions of dollars) ASSETS Derivative instruments Preferred stock $ 3 $ — $ — $ 3 Restricted cash equivalents Treasury fund 38 38 — — Executive deferred compensation plan assets Money market funds and short-term investments 35 14 21 — Life insurance contracts 46 — 27 19 Total $ 122 $ 52 $ 48 $ 22 LIABILITIES Derivative instruments (b) Natural gas (c) $ 4 $ 4 $ — $ — Executive deferred compensation plan liabilities Life insurance contracts 30 — 30 — Total $ 34 $ 4 $ 30 $ — (a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2014. (b) The fair values of derivative liabilities reflect netting by counterparty before the impact of collateral. (c) Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC. |
Reconciliations of Fair Value Measurements Using Significant Unobservable Inputs (Level 3) | Reconciliations of the beginning and ending balances of PHI’s fair value measurements using significant unobservable inputs (Level 3) for the years ended December 31, 2015 and 2014 are shown below: Year Ended December 31, 2015 2014 Preferred Stock Life Insurance Preferred Stock Life (millions of dollars) Balance as of January 1 $ 3 $ 19 $ — $ 19 Total gains (losses) (realized and unrealized): Included in income 15 5 — 3 Included in accumulated other comprehensive loss — — — — Included in regulatory liabilities — — — — Purchases — — — — Issuances — (3 ) 3 (3 ) Settlements — (2 ) — — Transfers in (out) of level 3 — — — — Balance as of December 31 $ 18 $ 19 $ 3 $ 19 |
Gains on Level 3 Instruments Included in Income | The breakdown of realized and unrealized gains on level 3 instruments included in income as a component of Other income or Other operation and maintenance expense for the periods below were as follows: Year Ended December 31, 2015 2014 (millions of dollars) Total net gains included in income for the period $ 20 $ 3 Change in unrealized gains relating to assets still held at reporting date $ 18 $ 3 |
Fair Value of Financial Liabilities Measured on Recurring Basis | Fair Value Measurements at December 31, 2015 Description Total Quoted Prices in Significant Significant (millions of dollars) LIABILITIES Debt instruments Long-term debt (a) $ 5,523 $ — $ 4,941 $ 582 Transition Bonds (b) 185 — 185 — Long-term project funding 5 — — 5 Total $ 5,713 $ — $ 5,126 $ 587 (a) The carrying amount for Long-term debt, net of unamortized discount, was $4,999 million as of December 31, 2015. (b) The carrying amount for Transition Bonds, including amounts due within one year, was $171 million as of December 31, 2015. Fair Value Measurements at December 31, 2014 Description Total Quoted Prices in Significant Significant (millions of dollars) LIABILITIES Debt instruments Long-term debt (a) $ 5,583 $ — $ 5,136 $ 447 Transition Bonds (b) 235 — 235 — Long-term project funding 28 — — 28 Total $ 5,846 $ — $ 5,371 $ 475 (a) The carrying amount for Long-term debt, net of unamortized discount, was $4,807 million as of December 31, 2014. (b) The carrying amount for Transition Bonds, including amounts due within one year, was $215 million as of December 31, 2014. |
Atlantic City Electric Co [Member] | |
Fair Value of Financial Assets and Liabilities Measured on Recurring Basis | The following tables set forth by level within the fair value hierarchy ACE’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. ACE’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. Fair Value Measurements at December 31, 2015 Description Total Quoted Prices in Active Markets for Identical Instruments (Level 1) (a) Significant Other Observable Inputs (Level 2) (a) Significant Unobservable Inputs (Level 3) (millions of dollars) ASSETS Cash equivalents and restricted cash equivalents Treasury funds $ 30 $ 30 $ — $ — (a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2015. Fair Value Measurements at December 31, 2014 Description Total Quoted Prices in Active Markets for Identical Instruments (Level 1) (a) Significant Other Observable Inputs (Level 2) (a) Significant Unobservable Inputs (Level 3) (millions of dollars) ASSETS Cash equivalents and restricted cash equivalents Treasury funds $ 24 $ 24 $ — $ — (a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2014. |
Fair Value of Financial Liabilities Measured on Recurring Basis | Fair Value Measurements at December 31, 2015 Description Total Quoted Prices in Significant Significant (millions of dollars) LIABILITIES Debt instruments Long-term debt (a) $ 1,140 $ — $ 860 $ 280 Transition Bonds (b) 185 — 185 — Total $ 1,325 $ — $ 1,045 $ 280 (a) The carrying amount for Long-term debt, net of unamortized discount, was $1,038 million as of December 31, 2015. (b) The carrying amount for Transition Bonds, including amounts due within one year, was $171 million as of December 31, 2015. Fair Value Measurements at December 31, 2014 Description Total Quoted Prices in Significant Significant (millions of dollars) LIABILITIES Debt instruments Long-term debt (a) $ 1,035 $ — $ 903 $ 132 Transition Bonds (b) 235 — 235 — Total $ 1,270 $ — $ 1,138 $ 132 (a) The carrying amount for Long-term debt, net of unamortized discount, was $903 million as of December 31, 2014. (b) The carrying amount for Transition Bonds, including amounts due within one year, was $215 million as of December 31, 2014. |
Potomac Electric Power Co [Member] | |
Fair Value of Financial Assets and Liabilities Measured on Recurring Basis | The following tables set forth, by level within the fair value hierarchy, Pepco’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Pepco’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. Fair Value Measurements at December 31, 2015 Description Total Quoted Prices in Significant Significant (millions of dollars) ASSETS Cash equivalents and restricted cash equivalents Treasury funds $ 2 $ 2 $ — $ — Executive deferred compensation plan assets Money market funds and short-term investments 26 11 15 — Life insurance contracts 42 — 23 19 Total $ 70 $ 13 $ 38 $ 19 LIABILITIES Executive deferred compensation plan liabilities Life insurance contracts $ 6 $ — $ 6 $ — Total $ 6 $ — $ 6 $ — (a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2015. Fair Value Measurements at December 31, 2014 Description Total Quoted Prices in Significant Significant (millions of dollars) ASSETS Restricted cash equivalents Treasury fund $ 5 $ 5 $ — $ — Executive deferred compensation plan assets Money market funds and short-term investments 34 13 21 — Life insurance contracts 41 — 23 18 Total $ 80 $ 18 $ 44 $ 18 LIABILITIES Executive deferred compensation plan liabilities Life insurance contracts $ 7 $ — $ 7 $ — Total $ 7 $ — $ 7 $ — (a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2014. |
Reconciliations of Fair Value Measurements Using Significant Unobservable Inputs (Level 3) | Reconciliations of the beginning and ending balances of Pepco’s fair value measurements using significant unobservable inputs (Level 3) for the years ended December 31, 2015 and 2014 are shown below. 2015 2014 Life Insurance Life Insurance (millions of dollars) Balance as of January 1 $ 18 $ 18 Total gains (losses) (realized and unrealized): Included in income 5 3 Included in accumulated other comprehensive loss — — Purchases — — Issuances (3 ) (3 ) Settlements (1 ) — Transfers in (out) of level 3 — — Balance as of December 31 $ 19 $ 18 |
Gains on Level 3 Instruments Included in Income | The breakdown of realized and unrealized gains on level 3 instruments included in income as a component of Other income or Other operation and maintenance expense for the periods below were as follows: Year Ended December 31, 2015 2014 (millions of dollars) Total gains included in income for the period $ 5 $ 3 Change in unrealized gains relating to assets still held at reporting date $ 3 $ 3 |
Fair Value of Financial Liabilities Measured on Recurring Basis | Fair Value Measurements at December 31, 2015 Description Total Quoted Prices in Significant Significant (millions of dollars) LIABILITIES Debt instruments Long-term debt (a) $ 2,673 $ — $ 2,673 $ — (a) The carrying amount for Long-term debt, net of unamortized discount, was $2,332 million as of December 31, 2015. Fair Value Measurements at December 31, 2014 Description Total Quoted Prices in Significant Significant (millions of dollars) LIABILITIES Debt instruments Long-term debt (a) $ 2,624 $ — $ 2,624 $ — Project funding 12 — — 12 Total $ 2,636 $ — $ 2,624 $ 12 (a) The carrying amount for Long-term debt, net of unamortized discount, was $2,124 million as of December 31, 2014. |
Delmarva Power & Light Co/De [Member] | |
Fair Value of Financial Assets and Liabilities Measured on Recurring Basis | The following tables set forth, by level within the fair value hierarchy, DPL’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. DPL’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. Fair Value Measurements at December 31, 2015 Description Total Quoted Prices in Active Markets for Identical Instruments (Level 1) (a) Significant Other Observable Inputs (Level 2) (a) Significant Unobservable Inputs (Level 3) (millions of dollars) LIABILITIES Derivative instruments (b) Natural gas (c) $ 2 $ 2 $ — $ — Executive deferred compensation plan liabilities Life insurance contracts 1 — 1 — Total $ 3 $ 2 $ 1 $ — (a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2015. (b) The fair value of derivative liabilities reflect netting by counterparty before the impact of collateral. (c) Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC. Fair Value Measurements at December 31, 2014 Description Total Quoted Prices in Significant Significant (millions of dollars) ASSETS Restricted cash equivalents Treasury funds $ 5 $ 5 $ — $ — Executive deferred compensation plan assets Money market funds 1 1 — — Life insurance contracts 1 — — 1 Total $ 7 $ 6 $ — $ 1 LIABILITIES Derivative instruments (b) Natural gas (c) $ 4 $ 4 $ — $ — Executive deferred compensation plan liabilities Life insurance contracts 1 — 1 — Total $ 5 $ 4 $ 1 $ — (a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2014. (b) The fair value of derivative liabilities reflect netting by counterparty before the impact of collateral. (c) Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC. |
Reconciliations of Fair Value Measurements Using Significant Unobservable Inputs (Level 3) | Reconciliations of the beginning and ending balances of DPL’s fair value measurements using significant unobservable inputs (Level 3) for the years ended December 31, 2015 and 2014 are shown below: Year Ended Year Ended Life Insurance Contracts Life Insurance Contracts (millions of dollars) Balance as of January 1 $ 1 $ 1 Total gains (losses) (realized and unrealized): Included in income — — Included in accumulated other comprehensive loss — — Included in regulatory liabilities — — Purchases — — Issuances — — Settlements (1 ) — Transfers in (out) of Level 3 — — Balance as of December 31 $ — $ 1 |
Fair Value of Financial Liabilities Measured on Recurring Basis | Fair Value Measurements at December 31, 2015 Description Total Quoted Prices in Significant Significant (millions of dollars) LIABILITIES Debt instruments Long-term debt (a) $ 1,183 $ — $ 1,080 $ 103 (a) The carrying amount for Long-term debt, including unamortized premium, was $1,170 million as of December 31, 2015. Fair Value Measurements at December 31, 2014 Description Total Quoted Prices in Significant Significant (millions of dollars) LIABILITIES Debt instruments Long-term debt (a) $ 1,123 $ — $ 1,016 $ 107 (a) The carrying amount for Long-term debt, including unamortized premium, was $1,071 million as of December 31, 2014. |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Schedule of Accrued Liabilities for Environmental Exposures | The total accrued liabilities for the environmental contingencies described below of PHI and its subsidiaries at December 31, 2015 are summarized as follows: Legacy Generation Transmission Regulated Non-Regulated Total (millions of dollars) Balance as of January 1 $ 17 $ 6 $ 5 $ 28 Accruals 7 3 — 10 Payments (4 ) (1 ) — (5 ) Balance as of December 31 20 8 5 33 Less amounts in Other Current Liabilities 3 1 — 4 Amounts in Other Deferred Credits $ 17 $ 7 $ 5 $ 29 |
Schedule of Commitments and Obligations | As of December 31, 2015, PHI and its subsidiaries were parties to a variety of agreements pursuant to which they were guarantors. The commitments and obligations were as follows: Guarantor PHI Pepco DPL ACE Total (millions of dollars) Guarantees associated with disposal of Conectiv Energy assets (a) $ 13 $ — $ — $ — $ 13 Guaranteed lease residual values (b) 3 5 6 5 19 Total $ 16 $ 5 $ 6 $ 5 $ 32 (a) Represents guarantees by PHI of Conectiv Energy’s derivative portfolio transferred in connection with the disposition of Conectiv Energy’s wholesale business. The derivative portfolio guarantee is currently $13 million and covers Conectiv Energy’s performance prior to the assignment. The guarantee will terminate in 2016. (b) Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $52 million, $9 million of which is a guarantee by PHI, $13 million by Pepco, $16 million by DPL and $14 million by ACE. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote. |
Atlantic City Electric Co [Member] | |
Schedule of Accrued Liabilities for Environmental Exposures | The total accrued liabilities for the environmental contingencies of ACE described below at December 31, 2015 are summarized as follows: Legacy Generation - (millions of dollars) Balance as of January 1 $ 1 Accruals — Payments — Balance as of December 31 1 Less amounts in Other Current Liabilities — Amounts in Other Deferred Credits $ 1 |
Potomac Electric Power Co [Member] | |
Schedule of Accrued Liabilities for Environmental Exposures | The total accrued liabilities for the environmental contingencies of Pepco described below at December 31, 2015 are summarized as follows: Transmission Distribution Legacy Total (millions of dollars) Balance as of January 1 $ 16 $ 3 $ 19 Accruals 4 3 7 Payments (2 ) — (2 ) Balance as of December 31 18 6 24 Less amounts in Other Current Liabilities 2 — 2 Amounts in Other Deferred Credits $ 16 $ 6 $ 22 |
Delmarva Power & Light Co/De [Member] | |
Schedule of Accrued Liabilities for Environmental Exposures | The total accrued liabilities for the environmental contingencies of DPL described below at December 31, 2015 are summarized as follows: Transmission Legacy Generation - Regulated Total (millions of dollars) Balance as of January 1 $ 1 $ 2 $ 3 Accruals 3 — 3 Payments (2 ) (1 ) (3 ) Balance as of December 31 2 1 3 Less amounts in Other Current Liabilities 1 1 2 Amounts in Other Deferred Credits $ 1 $ — $ 1 |
Accumulated Other Comprehensi46
Accumulated Other Comprehensive Loss (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Equity [Abstract] | |
Schedule of Components of Other Comprehensive Loss | The components of Pepco Holdings’ AOCL relating to continuing and discontinued operations are as follows. For additional information, see the consolidated statements of comprehensive income. Year Ended December 31, 2015 2014 2013 (millions of dollars) Balance as of January 1 $ (46 ) $ (34 ) $ (48 ) Treasury Lock Balance as of January 1 (9 ) (9 ) (10 ) Amount of pre-tax loss reclassified to Interest expense 1 1 1 Income tax expense — 1 — Balance as of December 31 (8 ) (9 ) (9 ) Pension and Other Postretirement Benefits Balance as of January 1 (37 ) (25 ) (32 ) Amount of amortization of net prior service cost and actuarial loss reclassified to Other operation and maintenance expense 6 5 5 Amount of net prior service cost and actuarial gain (loss) arising during the year 9 (25 ) 8 Income tax (benefit) expense 6 (8 ) 6 Balance as of December 31 (28 ) (37 ) (25 ) Commodity Derivatives Balance as of January 1 — — (6 ) Amount of net pre-tax loss reclassified to Income (loss) from discontinued operations before income tax — — 10 Income tax expense — — 4 Balance as of December 31 — — — Balance as of December 31 $ (36 ) $ (46 ) $ (34 ) |
Quarterly Financial Informati47
Quarterly Financial Information (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Schedule of Quarterly Financial Information | The totals of the four quarterly basic and diluted earnings per common share amounts may not equal the basic and diluted earnings per common share for the year due to changes in the number of shares of common stock outstanding during the year. 2015 First Quarter Second Quarter Third Quarter Fourth Quarter Total (millions of dollars, except per share amounts) Total Operating Revenue $ 1,371 $ 1,140 $ 1,362 $ 1,150 $ 5,023 Total Operating Expenses 1,229 1,001 1,179 941 (b) 4,350 Operating Income 142 139 183 209 673 Other Expenses (59 ) (59 ) (43 )(a) (65) (226) Income from Continuing Operations Before Income Tax Expense 83 80 140 144 447 Income Tax Expense Related to Continuing Operations 30 27 49 23 (c) 129 Net Income From Continuing Operations 53 53 91 121 318 Income from Discontinued Operations, net of taxes — — — 9 (d) 9 Net Income $ 53 $ 53 $ 91 $ 130 $ 327 Basic and Diluted Earnings Per Share of Common Stock: Earnings Per Share of Common Stock from Continuing Operations $ 0.21 $ 0.21 $ 0.36 $ 0.48 $ 1.25 Earnings Per Share of Common Stock from Discontinued Operations $ — $ — $ — $ 0.03 $ 0.04 Earnings Per Share of Common Stock $ 0.21 $ 0.21 $ 0.36 $ 0.51 $ 1.29 Cash Dividends Per Share of Common Stock $ 0.27 $ 0.27 $ 0.27 $ 0.27 $ 1.08 (a) Includes $15 million ($10 million after-tax) increase in fair value of preferred stock derivative. (b) Includes gains of $46 million ($27 million after-tax) associated with the sale of Pepco non-utility land. (c) Includes income tax benefit of $47 million associated with the Global Tax Settlement and a tax charge of $7 million to correct prior period errors. (d) Includes income tax benefit of $9 million associated with the Global Tax Settlement. 2014 First Quarter Second Quarter Third Quarter Fourth Quarter Total (millions of dollars, except per share amounts) Total Operating Revenue (a) $ 1,330 $ 1,117 $ 1,313 $ 1,118 $ 4,878 Total Operating Expenses (b) 1,157 966 1,147 1,004 (c) 4,274 Operating Income 173 151 166 114 604 Other Expenses (52 ) (53 ) (53 ) (66 ) (224 ) Income from Continuing Operations Before Income Tax Expense 121 98 113 48 380 Income Tax Expense Related to Continuing Operations 46 45 34 13 138 Net Income $ 75 $ 53 $ 79 $ 35 $ 242 Basic and Diluted Earnings Per Share of Common Stock $ 0.30 $ 0.21 $ 0.31 $ 0.14 $ 0.96 Cash Dividends Per Share of Common Stock $ 0.27 $ 0.27 $ 0.27 $ 0.27 $ 1.08 (a) During the fourth quarter of 2014, ACE reversed unbilled revenue of $3 million ($2 million after-tax) to correct an error that had overstated operating revenue in the third quarter of 2014. (b) Includes pre-tax impairment losses of $53 million ($32 million after-tax) and $28 million ($16 million after-tax) in the third and fourth quarters of 2014, respectively, at Pepco Energy Services associated with its combined heat and power thermal generating facilities and operations in Atlantic City. (c) Includes a charge of $3 million ($2 million after-tax) to correct a prior period error related to the recoverability of certain regulatory assets at ACE. |
Atlantic City Electric Co [Member] | |
Schedule of Quarterly Financial Information | Quarterly data normally vary seasonally because of temperature variations and differences between summer and winter rates. Therefore, comparisons by quarter within a year are not meaningful. 2015 First Second Third Fourth Total (millions of dollars) Total Operating Revenue $ 333 $ 286 $ 387 $ 292 $ 1,298 Total Operating Expenses 313 254 349 252 1,168 Operating Income 20 32 38 40 130 Other Expenses (14 ) (15 ) (17 ) (15 ) (61 ) Income Before Income Tax Expense 6 17 21 25 69 Income Tax Expense 2 7 7 15 (a) 31 Net Income $ 4 $ 10 $ 14 $ 10 $ 38 (a) Includes income tax charge of $3 million associated with the Global Tax Settlement and a tax charge of $2 million to correct prior period errors. 2014 First Second Third Fourth Total (millions of dollars) Total Operating Revenue (a) $ 340 $ 253 $ 347 $ 273 $ 1,213 Total Operating Expenses 309 228 295 246 (b) 1,078 Operating Income 31 25 52 27 135 Other Expenses (15 ) (15 ) (15 ) (17 ) (62 ) Income Before Income Tax Expense 16 10 37 10 73 Income Tax Expense 6 4 14 4 28 Net Income $ 10 $ 6 $ 23 $ 6 $ 45 (a) During the fourth quarter of 2014, ACE reversed unbilled revenue of $3 million ($2 million after-tax) to correct an error that had overstated operating revenue in the third quarter of 2014. (b) Includes a charge of $3 million ($2 million after-tax) to correct a prior period error related to the recoverability of certain regulatory assets. |
Potomac Electric Power Co [Member] | |
Schedule of Quarterly Financial Information | Quarterly data normally vary seasonally because of temperature variations and differences between summer and winter rates. Therefore, comparisons by quarter within a year are not meaningful. 2015 First Second Third Fourth Total (millions of dollars) Total Operating Revenue $ 556 $ 518 $ 612 $ 503 $ 2,189 Total Operating Expenses 493 435 497 379 (a) 1,804 Operating Income 63 83 115 124 385 Other Expenses (25 ) (23 ) (23 ) (29 ) (100 ) Income Before Income Tax Expense 38 60 92 95 285 Income Tax Expense 12 18 32 36 (b) 98 Net Income $ 26 $ 42 $ 60 $ 59 $ 187 (a) Includes gains of $46 million ($27 million after-tax) associated with the sale of non-utility land. (b) Includes net income tax benefit of $9 million associated with the Global Tax Settlement, a tax charge of $3 million for an uncertain tax position not related to the Global Tax Settlement and a tax charge of $6 million to correct prior period errors. 2014 First Second Third Fourth Total (millions of dollars) Total Operating Revenue $ 535 $ 508 $ 587 $ 471 $ 2,101 Total Operating Expenses 469 414 462 408 1,753 Operating Income 66 94 125 63 348 Other Expenses (18 ) (20 ) (20 ) (27 ) (85 ) Income Before Income Tax Expense 48 74 105 36 263 Income Tax Expense 16 28 38 10 92 Net Income $ 32 $ 46 $ 67 $ 26 $ 171 |
Delmarva Power & Light Co/De [Member] | |
Schedule of Quarterly Financial Information | Quarterly data normally vary seasonally because of temperature variations and differences between summer and winter rates. Therefore, comparisons by quarter within a year are not meaningful. 2015 First Second Third Quarter Fourth Total (millions of dollars) Total Operating Revenue $ 423 $ 275 $ 317 $ 303 $ 1,318 Total Operating Expenses 361 251 285 256 1,153 Operating Income 62 24 32 47 165 Other Expenses (9 ) (11 ) (8 ) (12 ) (40 ) Income Before Income Tax Expense 53 13 24 35 125 Income Tax Expense 21 5 9 14 (a) 49 Net Income $ 32 $ 8 $ 15 $ 21 $ 76 (a) Includes income tax charge of $3 million associated with the Global Tax Settlement. 2014 First Quarter Second Third Quarter Fourth Total (millions of dollars) Total Operating Revenue $ 397 $ 279 $ 309 $ 308 $ 1,293 Total Operating Expenses 326 239 264 257 1,086 Operating Income 71 40 45 51 207 Other Expenses (9 ) (8 ) (9 ) (12 ) (38 ) Income Before Income Tax Expense 62 32 36 39 169 Income Tax Expense 25 13 13 14 65 Net Income $ 37 $ 19 $ 23 $ 25 $ 104 |
Discontinued Operations (Tables
Discontinued Operations (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Income (Loss) from Discontinued Operations, net of income taxes | PHI’s income (loss) from discontinued operations, net of income taxes, is comprised of the following: For the Year Ended December 31, 2015 2014 2013 (millions of dollars) Cross-border energy lease investments $ 9 $ — $ (327 ) Pepco Energy Services’ retail electric and natural gas supply businesses — — 5 Income (loss) from discontinued operations, net of income taxes $ 9 $ — $ (322 ) |
Discontinued Operations [Member] | |
Derivative Gain (Loss) for Retail Electric and Natural Gas Supply Businesses | For the years ended December 31, 2015, 2014, and 2013, the amount of the derivative gain (loss) for the retail electric and natural gas supply businesses of Pepco Energy Services recognized in Income (loss) from discontinued operations, net of income taxes is provided in the table below: For the Year Ended December 31, 2015 2014 2013 (millions of dollars) Reclassification of mark-to-market to realized on settlement of contracts $ — $ — $ 10 Unrealized mark-to-market loss — — — Total net gain $ — $ — $ 10 |
Cross-Border Energy Lease Investments [Member] | |
Income (Loss) from Discontinued Operations, net of income taxes | The operating results for the cross-border energy lease investments are as follows: For the Year Ended December 31, 2015 2014 2013 (millions of dollars) Operating revenue from PHI’s cross-border energy lease investments $ — $ — $ 7 Non-cash charge to reduce carrying value of PHI’s cross-border energy lease investments — — (373 ) Total operating revenue $ — $ — $ (366 ) Income (loss) from operations of discontinued operations, net of income taxes (a) $ 9 $ — $ (325 ) Net losses associated with the early termination of the cross-border energy lease investments, net of income taxes — — (2 ) Income (loss) from discontinued operations, net of income taxes $ 9 $ — $ (327 ) (a) Includes income tax benefit of approximately $9 million and $44 million for the years ended December 31, 2015 and 2013, respectively. |
Pepco Energy Services [Member] | Discontinued Operations [Member] | |
Income (Loss) from Discontinued Operations, net of income taxes | The operating results for the retail electric and natural gas supply businesses of Pepco Energy Services are as follows: For the Year Ended December 31, 2015 2014 2013 (millions of dollars) Operating revenue $ — $ — $ 84 Income from operations of discontinued operations, net of income taxes $ — $ — $ 4 Net gains associated with accelerated disposition of retail electric and natural gas contracts, net of income taxes — — 1 Income from discontinued operations, net of income taxes (a) $ — $ — $ 5 (a) Includes income tax expense of approximately $3 million for the year ended December 31, 2013. |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Atlantic City Electric Co [Member] | |
Schedule of Related Party Transactions Included in Financial Statements | In addition to the PHI Service Company charges described above, ACE’s consolidated financial statements include the following related party transactions in its consolidated statements of income: For the Year Ended December 31, 2015 2014 2013 (millions of dollars) Meter reading services provided by Millennium Account Services LLC (an ACE affiliate) (a) $ (4 ) $ (4 ) $ (4 ) Intercompany lease transactions (a) (1 ) (1 ) (1 ) Intercompany use revenue (b) 1 2 3 (a) Included in Other operation and maintenance expense. (b) Included in Operating revenue. As of December 31, 2015 and 2014, ACE had the following balances on its consolidated balance sheets due to related parties: 2015 2014 (millions of dollars) Payable to Related Party (current) (a) PHI Service Company $ (15 ) $ (14 ) Other (1 ) (1 ) Total $ (16 ) $ (15 ) (a) Included in Accounts payable due to associated companies. |
Potomac Electric Power Co [Member] | |
Schedule of Related Party Transactions Included in Financial Statements | As of December 31, 2015 and 2014, Pepco had the following balances on its balance sheets due to related parties: 2015 2014 (millions of dollars) Payable to Related Party (current) (a) PHI Service Company $ (25 ) $ (27 ) Pepco Energy Services (b) (4 ) (2 ) Other (1 ) (1 ) Total $ (30 ) $ (30 ) (a) Included in Accounts payable due to associated companies. (b) Pepco bills customers on behalf of Pepco Energy Services where Pepco Energy Services has performed work for certain government agencies under a General Services Administration area-wide agreement. Amount also includes charges for utility work performed by Pepco Energy Services on behalf of Pepco. |
Delmarva Power & Light Co/De [Member] | |
Schedule of Related Party Transactions Included in Financial Statements | In addition to the PHI Service Company charges described above, DPL’s financial statements include the following related party transactions in its statements of income: For the Year Ended December 31, 2015 2014 2013 (millions of dollars) Intercompany lease transactions (a) $ 4 $ 5 $ 4 (a) Included in Electric revenue. As of December 31, 2015 and 2014, DPL had the following balances on its balance sheets due to related parties: 2015 2014 (millions of dollars) Payable to Related Party (current) (a) PHI Service Company $ (19 ) $ (18 ) Other (1 ) 1 Total $ (20 ) $ (17 ) (a) Included in Accounts payable due to associated companies. |
Organization - Additional Infor
Organization - Additional Information (Detail) - USD ($) | Jul. 24, 2015 | Apr. 27, 2015 | Jan. 26, 2015 | Oct. 27, 2014 | Jul. 29, 2014 | Apr. 30, 2014 | Apr. 29, 2014 | Dec. 31, 2015 | Dec. 31, 2014 |
Organization [Line Items] | |||||||||
Common stock, par value | $ 0.01 | $ 0.01 | $ 0.01 | ||||||
Right to receive cash under cancellation of shares | $ 27.25 | ||||||||
Amount of Non Voting Series A Preferred Stock Purchase price | $ 54,000,000 | $ 126,000,000 | |||||||
Termination fee | $ 259,000,000 | ||||||||
Reimbursement of termination related expenses | $ 40,000,000 | ||||||||
Potomac Electric Power Co [Member] | |||||||||
Organization [Line Items] | |||||||||
Common stock, par value | $ 0.01 | $ 0.01 | |||||||
Delmarva Power & Light Co/De [Member] | |||||||||
Organization [Line Items] | |||||||||
Common stock, par value | $ 0.01 | 2.25 | 2.25 | ||||||
Right to receive cash under cancellation of shares | $ 27.25 | ||||||||
Termination fee | $ 259,000,000 | ||||||||
Reimbursement of termination related expenses | $ 40,000,000 | ||||||||
Atlantic City Electric Co [Member] | |||||||||
Organization [Line Items] | |||||||||
Common stock, par value | $ 0.01 | 3 | $ 3 | ||||||
Right to receive cash under cancellation of shares | $ 27.25 | ||||||||
Termination fee | $ 259,000,000 | ||||||||
Reimbursement of termination related expenses | 40,000,000 | ||||||||
Terminations Due to New Acquisition Proposal [Member] | |||||||||
Organization [Line Items] | |||||||||
Termination fee | 293,000,000 | ||||||||
Terminations Due to New Acquisition Proposal [Member] | Delmarva Power & Light Co/De [Member] | |||||||||
Organization [Line Items] | |||||||||
Termination fee | 293,000,000 | ||||||||
Terminations Due to New Acquisition Proposal [Member] | Atlantic City Electric Co [Member] | |||||||||
Organization [Line Items] | |||||||||
Termination fee | 293,000,000 | ||||||||
Non-Voting Series A Preferred Stock [Member] | |||||||||
Organization [Line Items] | |||||||||
Issuance of non-voting Series A Preferred Stock, shares issued | 9,000 | ||||||||
Non-voting Series A Preferred Stock, par value | $ 0.01 | ||||||||
Non-voting Series A Preferred Stock, shares purchased price | $ 90,000,000 | ||||||||
Non-voting Series A Preferred Stock, maximum number of shares issued | 1,800 | 1,800 | 1,800 | 1,800 | 1,800 | ||||
Amount of Non Voting Series A Preferred Stock Purchase price | $ 18,000,000 | $ 18,000,000 | $ 18,000,000 | $ 18,000,000 | $ 18,000,000 | ||||
Non-voting Series A Preferred Stock, maximum aggregate consideration | 180,000,000 | ||||||||
Redemption of preferred stock at purchase price | 10,000 | ||||||||
Non-voting Series A Preferred Stock, cumulative, non-participating cash dividend | 0.10% | ||||||||
Non-Voting Series A Preferred Stock [Member] | Potomac Electric Power Co [Member] | |||||||||
Organization [Line Items] | |||||||||
Issuance of non-voting Series A Preferred Stock, shares issued | 9,000 | ||||||||
Non-voting Series A Preferred Stock, par value | $ 0.01 | ||||||||
Non-voting Series A Preferred Stock, shares purchased price | $ 90,000,000 | ||||||||
Non-voting Series A Preferred Stock, maximum number of shares issued | 1,800 | 1,800 | 1,800 | 1,800 | 1,800 | ||||
Amount of Non Voting Series A Preferred Stock Purchase price | $ 90,000,000 | $ 90,000,000 | $ 90,000,000 | $ 90,000,000 | $ 90,000,000 | ||||
Non-voting Series A Preferred Stock, maximum aggregate consideration | 180,000,000 | ||||||||
Non-voting Series A Preferred Stock, cumulative, non-participating cash dividend | 0.10% | ||||||||
Non-Voting Series A Preferred Stock [Member] | Delmarva Power & Light Co/De [Member] | |||||||||
Organization [Line Items] | |||||||||
Issuance of non-voting Series A Preferred Stock, shares issued | 9,000 | ||||||||
Non-voting Series A Preferred Stock, par value | $ 0.01 | ||||||||
Non-voting Series A Preferred Stock, shares purchased price | $ 90,000,000 | ||||||||
Non-voting Series A Preferred Stock, maximum number of shares issued | 1,800 | 1,800 | 1,800 | 1,800 | 1,800 | ||||
Amount of Non Voting Series A Preferred Stock Purchase price | $ 90,000,000 | $ 90,000,000 | $ 90,000,000 | $ 90,000,000 | $ 90,000,000 | ||||
Non-voting Series A Preferred Stock, maximum aggregate consideration | 180,000,000 | ||||||||
Redemption of preferred stock at purchase price | 10,000 | ||||||||
Non-voting Series A Preferred Stock, cumulative, non-participating cash dividend | 0.10% | ||||||||
Non-Voting Series A Preferred Stock [Member] | Atlantic City Electric Co [Member] | |||||||||
Organization [Line Items] | |||||||||
Issuance of non-voting Series A Preferred Stock, shares issued | 9,000 | ||||||||
Non-voting Series A Preferred Stock, par value | $ 0.01 | ||||||||
Non-voting Series A Preferred Stock, shares purchased price | $ 90,000,000 | ||||||||
Non-voting Series A Preferred Stock, maximum number of shares issued | 1,800 | 1,800 | 1,800 | 1,800 | 1,800 | ||||
Amount of Non Voting Series A Preferred Stock Purchase price | $ 90,000,000 | $ 90,000,000 | $ 90,000,000 | $ 90,000,000 | $ 90,000,000 | ||||
Non-voting Series A Preferred Stock, maximum aggregate consideration | $ 180,000,000 | ||||||||
Redemption of preferred stock at purchase price | $ 10,000 | ||||||||
Non-voting Series A Preferred Stock, cumulative, non-participating cash dividend | 0.10% | ||||||||
Maximum [Member] | Non-Voting Series A Preferred Stock [Member] | |||||||||
Organization [Line Items] | |||||||||
Non-voting Series A Preferred Stock, maximum number of shares issued | 18,000 | ||||||||
Maximum [Member] | Non-Voting Series A Preferred Stock [Member] | Potomac Electric Power Co [Member] | |||||||||
Organization [Line Items] | |||||||||
Non-voting Series A Preferred Stock, maximum number of shares issued | 18,000 | ||||||||
Maximum [Member] | Non-Voting Series A Preferred Stock [Member] | Delmarva Power & Light Co/De [Member] | |||||||||
Organization [Line Items] | |||||||||
Non-voting Series A Preferred Stock, maximum number of shares issued | 18,000 | ||||||||
Maximum [Member] | Non-Voting Series A Preferred Stock [Member] | Atlantic City Electric Co [Member] | |||||||||
Organization [Line Items] | |||||||||
Non-voting Series A Preferred Stock, maximum number of shares issued | 18,000 | ||||||||
Maximum [Member] | Exelon [Member] | |||||||||
Organization [Line Items] | |||||||||
Out-of-pocket expenses, connection with the Merger Agreement | $ 40,000,000 | ||||||||
Maximum [Member] | Exelon [Member] | Delmarva Power & Light Co/De [Member] | |||||||||
Organization [Line Items] | |||||||||
Out-of-pocket expenses, connection with the Merger Agreement | 40,000,000 | ||||||||
Maximum [Member] | Exelon [Member] | Atlantic City Electric Co [Member] | |||||||||
Organization [Line Items] | |||||||||
Out-of-pocket expenses, connection with the Merger Agreement | $ 40,000,000 |
Significant Accounting Polici51
Significant Accounting Policies - Additional Information (Detail) - USD ($) | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2010 | |
Significant Accounting Policies [Line Items] | ||||
Unbilled revenue | $ 139,000,000 | $ 172,000,000 | ||
Taxes included in gross revenues | $ 322,000,000 | $ 321,000,000 | $ 346,000,000 | |
Restricted stock awards vesting period | 1 year | 1 year | ||
Unbilled receivables billing period | 1 month | |||
Estimated fair value of an asset | Greater than 50% | |||
AFUDC for borrowed funds | $ 8,000,000 | $ 7,000,000 | 7,000,000 | |
AFUDC for equity component | $ 14,000,000 | 13,000,000 | 11,000,000 | |
Number of subsidiaries, allocated | 3 | |||
Retained earnings | $ 617,000,000 | 565,000,000 | ||
Asset Removal Costs [Member] | ||||
Significant Accounting Policies [Line Items] | ||||
Regulatory liabilities | $ 211,000,000 | 250,000,000 | ||
Maximum [Member] | ||||
Significant Accounting Policies [Line Items] | ||||
Original maturities of cash and cash equivalents | 3 months | |||
Time-Based Restricted Stock Units were Granted to Each Non-Employee Director [Member] | ||||
Significant Accounting Policies [Line Items] | ||||
Restricted stock awards vesting period | 3 years | |||
Performance Based Restricted Stock Units [Member] | ||||
Significant Accounting Policies [Line Items] | ||||
Restricted stock awards vesting period | 3 years | |||
Delmarva Power & Light Co/De [Member] | ||||
Significant Accounting Policies [Line Items] | ||||
Unbilled revenue | $ 37,000,000 | 63,000,000 | ||
Taxes included in gross revenues | $ 18,000,000 | 16,000,000 | 17,000,000 | |
Unbilled receivables billing period | 1 month | |||
Estimated fair value of an asset | Greater than 50% | |||
AFUDC for borrowed funds | $ 1,000,000 | 1,000,000 | 2,000,000 | |
AFUDC for equity component | $ 1,000,000 | 2,000,000 | $ 2,000,000 | |
Preferred stock, shares outstanding | 0 | |||
Retained earnings | $ 625,000,000 | 641,000,000 | ||
Delmarva Power & Light Co/De [Member] | Asset Removal Costs [Member] | ||||
Significant Accounting Policies [Line Items] | ||||
Regulatory liabilities | $ 153,000,000 | $ 166,000,000 | ||
Delmarva Power & Light Co/De [Member] | Maximum [Member] | ||||
Significant Accounting Policies [Line Items] | ||||
Original maturities of cash and cash equivalents | 3 months | |||
Delmarva Power & Light Co/De [Member] | Transmission and Distribution [Member] | ||||
Significant Accounting Policies [Line Items] | ||||
Annual Depreciation Rate | 2.60% | 2.60% | 2.60% | |
Atlantic City Electric Co [Member] | ||||
Significant Accounting Policies [Line Items] | ||||
Unbilled revenue | $ 26,000,000 | $ 32,000,000 | ||
Taxes included in gross revenues | $ 0 | 1,000,000 | $ 11,000,000 | |
Unbilled receivables billing period | 1 month | |||
Awards received from the U.S. DOE | $ 19,000,000 | |||
AFUDC for borrowed funds | $ 1,000,000 | 1,000,000 | ||
AFUDC for equity component | $ 1,000,000 | 1,000,000 | ||
Preferred stock, shares outstanding | 0 | |||
Retained earnings | $ 235,000,000 | $ 209,000,000 | ||
Securitization debt capitalization rate | 30.00% | |||
Atlantic City Electric Co [Member] | Maximum [Member] | ||||
Significant Accounting Policies [Line Items] | ||||
Original maturities of cash and cash equivalents | 3 months | |||
AFUDC for borrowed funds | 1,000,000 | |||
AFUDC for equity component | $ 1,000,000 | |||
Atlantic City Electric Co [Member] | Transmission and Distribution [Member] | ||||
Significant Accounting Policies [Line Items] | ||||
Annual Depreciation Rate | 2.60% | 2.60% | 2.80% | |
Potomac Electric Power Co [Member] | ||||
Significant Accounting Policies [Line Items] | ||||
Unbilled revenue | $ 76,000,000 | $ 77,000,000 | ||
Taxes included in gross revenues | $ 304,000,000 | 304,000,000 | $ 318,000,000 | |
Unbilled receivables billing period | 1 month | |||
Awards received from the U.S. DOE | $ 149,000,000 | |||
AFUDC for borrowed funds | $ 6,000,000 | 5,000,000 | 5,000,000 | |
AFUDC for equity component | $ 12,000,000 | 10,000,000 | $ 9,000,000 | |
Preferred stock, shares outstanding | 0 | |||
Retained earnings | $ 1,118,000,000 | 1,077,000,000 | ||
Potomac Electric Power Co [Member] | Asset Removal Costs [Member] | ||||
Significant Accounting Policies [Line Items] | ||||
Regulatory liabilities | $ 58,000,000 | $ 84,000,000 | ||
Potomac Electric Power Co [Member] | Maximum [Member] | ||||
Significant Accounting Policies [Line Items] | ||||
Original maturities of cash and cash equivalents | 3 months | |||
Potomac Electric Power Co [Member] | Transmission and Distribution [Member] | ||||
Significant Accounting Policies [Line Items] | ||||
Annual Depreciation Rate | 2.30% | 2.30% | 2.20% |
Significant Accounting Polici52
Significant Accounting Policies - Annual Depreciation Rates (Detail) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Transmission and Distribution [Member] | Potomac Electric Power Co [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Annual Depreciation Rate | 2.30% | 2.30% | 2.20% |
Transmission and Distribution [Member] | Delmarva Power & Light Co/De [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Annual Depreciation Rate | 2.60% | 2.60% | 2.60% |
Transmission and Distribution [Member] | Atlantic City Electric Co [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Annual Depreciation Rate | 2.60% | 2.60% | 2.80% |
Generation [Member] | Pepco Energy Services [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Annual Depreciation Rate | 0.60% | 1.20% | 0.40% |
Newly Adopted Accounting Stan53
Newly Adopted Accounting Standards - Effects of the Retrospective Application of Newly Adopted Accounting Standards on Reported Balances (Detail) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Other (within other assets) | $ 129 | $ 121 |
Prepaid expenses and other | 72 | 63 |
Long-term debt | 4,656 | 4,397 |
Transition bonds issued by ACE Funding | 124 | 170 |
Deferred income taxes, net (within current assets) | 0 | 0 |
Deferred income taxes, net (within other assets) | 15 | 17 |
Other (within current liabilities) | 287 | 305 |
Deferred income tax liabilities, net | 3,393 | 3,242 |
Potomac Electric Power Co [Member] | ||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Other (within other assets) | 42 | 43 |
Prepaid expenses and other | 20 | 21 |
Long-term debt | 2,301 | 2,096 |
Other (within current liabilities) | 68 | 93 |
Deferred income tax liabilities, net | 1,721 | 1,579 |
Delmarva Power & Light Co/De [Member] | ||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Other (within other assets) | 1 | 4 |
Prepaid expenses and other | 10 | 12 |
Long-term debt | 1,061 | 963 |
Other (within current liabilities) | 39 | 41 |
Deferred income tax liabilities, net | 941 | 878 |
Atlantic City Electric Co [Member] | ||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Other (within other assets) | 4 | 5 |
Prepaid expenses and other | 1 | 3 |
Long-term debt | 1,030 | 882 |
Transition bonds issued by ACE Funding | 124 | 170 |
Other (within current liabilities) | 21 | 22 |
Deferred income tax liabilities, net | $ 888 | 855 |
As Filed [Member] | ||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Other (within other assets) | 166 | |
Long-term debt | 4,441 | |
Transition bonds issued by ACE Funding | 171 | |
Deferred income taxes, net (within current assets) | 50 | |
Other (within current liabilities) | 314 | |
Deferred income tax liabilities, net | 3,266 | |
As Filed [Member] | Potomac Electric Power Co [Member] | ||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Other (within other assets) | 71 | |
Long-term debt | 2,124 | |
Deferred income taxes, net (within current assets) | 14 | |
Other (within current liabilities) | 102 | |
Deferred income tax liabilities, net | 1,584 | |
As Filed [Member] | Delmarva Power & Light Co/De [Member] | ||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Other (within other assets) | 12 | |
Long-term debt | 971 | |
Deferred income taxes, net (within current assets) | 16 | |
Other (within current liabilities) | 42 | |
Deferred income tax liabilities, net | 893 | |
As Filed [Member] | Atlantic City Electric Co [Member] | ||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Other (within other assets) | 12 | |
Prepaid expenses and other | 13 | |
Long-term debt | 888 | |
Transition bonds issued by ACE Funding | 171 | |
Deferred income tax liabilities, net | 865 | |
Scenario, Adjustment [Member] | ||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Other (within other assets) | (45) | |
Long-term debt | (44) | |
Transition bonds issued by ACE Funding | (1) | |
Deferred income taxes, net (within current assets) | (50) | |
Deferred income taxes, net (within other assets) | 17 | |
Other (within current liabilities) | (9) | |
Deferred income tax liabilities, net | (24) | |
Scenario, Adjustment [Member] | Potomac Electric Power Co [Member] | ||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Other (within other assets) | (28) | |
Long-term debt | (28) | |
Deferred income taxes, net (within current assets) | (14) | |
Other (within current liabilities) | (9) | |
Deferred income tax liabilities, net | (5) | |
Scenario, Adjustment [Member] | Delmarva Power & Light Co/De [Member] | ||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Other (within other assets) | (8) | |
Long-term debt | (8) | |
Deferred income taxes, net (within current assets) | (16) | |
Other (within current liabilities) | (1) | |
Deferred income tax liabilities, net | (15) | |
Scenario, Adjustment [Member] | Atlantic City Electric Co [Member] | ||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Other (within other assets) | (7) | |
Prepaid expenses and other | (10) | |
Long-term debt | (6) | |
Transition bonds issued by ACE Funding | (1) | |
Deferred income tax liabilities, net | $ (10) |
Segment Information - Segment F
Segment Information - Segment Financial Information for Continuing Operations (Detail) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Segment Reporting Information [Line Items] | |||||||||||
Operating Revenue | $ 1,150 | $ 1,362 | $ 1,140 | $ 1,371 | $ 1,118 | $ 1,313 | $ 1,117 | $ 1,330 | $ 5,023 | $ 4,878 | $ 4,666 |
Operating Expenses | 941 | 1,179 | 1,001 | 1,229 | 1,004 | 1,147 | 966 | 1,157 | 4,350 | 4,274 | 3,998 |
Operating Income (Loss) | 209 | 183 | 139 | 142 | 114 | 166 | 151 | 173 | 673 | 604 | 668 |
Interest Expense | 280 | 268 | 273 | ||||||||
Other income | 54 | 44 | 34 | ||||||||
Income Tax Expense (Benefit) | 23 | 49 | 27 | 30 | 13 | $ 34 | $ 45 | $ 46 | 129 | 138 | 319 |
Net Income (Loss) from Continuing Operations | 121 | $ 91 | $ 53 | $ 53 | 318 | 242 | 110 | ||||
Total Assets | 16,326 | 15,589 | 16,326 | 15,589 | 14,778 | ||||||
Construction Expenditures | 1,230 | 1,223 | 1,310 | ||||||||
Power Delivery [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Operating Revenue | 4,805 | 4,607 | 4,472 | ||||||||
Operating Expenses | 4,124 | 3,916 | 3,828 | ||||||||
Operating Income (Loss) | 681 | 691 | 644 | ||||||||
Interest Expense | 238 | 226 | 228 | ||||||||
Other income | 36 | 40 | 28 | ||||||||
Income Tax Expense (Benefit) | 177 | 185 | 155 | ||||||||
Net Income (Loss) from Continuing Operations | 302 | 320 | 289 | ||||||||
Total Assets | 14,413 | 13,636 | 14,413 | 13,636 | 12,868 | ||||||
Construction Expenditures | 1,196 | 1,144 | 1,194 | ||||||||
Pepco Energy Services [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Operating Revenue | 223 | 278 | 203 | ||||||||
Operating Expenses | 224 | 354 | 201 | ||||||||
Operating Income (Loss) | (1) | (76) | 2 | ||||||||
Interest Expense | 1 | 1 | |||||||||
Other income | 1 | 2 | 3 | ||||||||
Income Tax Expense (Benefit) | (4) | (36) | 1 | ||||||||
Net Income (Loss) from Continuing Operations | 4 | (39) | 3 | ||||||||
Total Assets | 221 | 249 | 221 | 249 | 337 | ||||||
Construction Expenditures | 3 | 3 | 4 | ||||||||
Corporate and Other [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Operating Revenue | (5) | (7) | (9) | ||||||||
Operating Expenses | 2 | 4 | (31) | ||||||||
Operating Income (Loss) | (7) | (11) | 22 | ||||||||
Interest Expense | 42 | 41 | 44 | ||||||||
Other income | 17 | 2 | 3 | ||||||||
Income Tax Expense (Benefit) | (44) | (11) | 163 | ||||||||
Net Income (Loss) from Continuing Operations | 12 | (39) | (182) | ||||||||
Total Assets | $ 1,692 | $ 1,704 | 1,692 | 1,704 | 1,573 | ||||||
Construction Expenditures | $ 31 | $ 76 | $ 112 |
Segment Information - Segment55
Segment Information - Segment Financial Information for Continuing Operations (Parenthetical) (Detail) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Segment Reporting Information [Line Items] | |||||||||||
Goodwill | $ 1,406 | $ 1,407 | $ 1,406 | $ 1,407 | |||||||
Operating Revenue | 1,150 | $ 1,362 | $ 1,140 | $ 1,371 | 1,118 | $ 1,313 | $ 1,117 | $ 1,330 | 5,023 | 4,878 | $ 4,666 |
Operating Expenses | 941 | 1,179 | 1,001 | 1,229 | 1,004 | 1,147 | 966 | 1,157 | 4,350 | 4,274 | 3,998 |
Interest Expense | 280 | 268 | 273 | ||||||||
Depreciation and amortization | 651 | 549 | 473 | ||||||||
Gains on sales of land | 46 | 46 | |||||||||
Gains on sales of land, after tax | 27 | ||||||||||
Increase in fair value of preferred stock derivative | 15 | 15 | |||||||||
Increase in fair value of preferred stock derivative, after-tax | 10 | ||||||||||
Income Tax Benefit | (23) | $ (49) | $ (27) | $ (30) | (13) | $ (34) | $ (45) | $ (46) | (129) | (138) | (319) |
Impairment losses | 81 | 4 | |||||||||
Tax Settlement [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Income Tax Benefit | 47 | ||||||||||
Power Delivery [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Operating Revenue | 4,805 | 4,607 | 4,472 | ||||||||
Operating Expenses | 4,124 | 3,916 | 3,828 | ||||||||
Interest Expense | 238 | 226 | 228 | ||||||||
Depreciation and amortization | 606 | 511 | 439 | ||||||||
Gains on sales of land | 46 | ||||||||||
Gains on sales of land, after tax | 27 | ||||||||||
Income Tax Benefit | (177) | (185) | (155) | ||||||||
Interest benefit on uncertain tax positions | 12 | ||||||||||
Power Delivery [Member] | Tax Settlement [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Income Tax Benefit | 3 | ||||||||||
Power Delivery [Member] | Operating Segments [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Goodwill | $ 1,400 | $ 1,400 | 1,400 | 1,400 | 1,400 | ||||||
Inter Company Amounts [Member] | Corporate and Other [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Operating Revenue | (5) | (7) | (10) | ||||||||
Operating Expenses | (4) | (7) | (9) | ||||||||
Interest Expense | (5) | (4) | (5) | ||||||||
Pepco Energy Services [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Operating Revenue | 223 | 278 | 203 | ||||||||
Operating Expenses | 224 | 354 | 201 | ||||||||
Interest Expense | 1 | 1 | |||||||||
Depreciation and amortization | 4 | 7 | 6 | ||||||||
Income Tax Benefit | 4 | 36 | (1) | ||||||||
Impairment losses | 81 | ||||||||||
Impairment losses, after-tax | 48 | ||||||||||
Pepco Energy Services [Member] | Tax Settlement [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Income Tax Benefit | 1 | ||||||||||
Pepco Energy Services [Member] | Operating Segments [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Impairment losses | 81 | 4 | |||||||||
Impairment losses, after-tax | 48 | 3 | |||||||||
Corporate and Other [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Operating Revenue | (5) | (7) | (9) | ||||||||
Operating Expenses | 2 | 4 | (31) | ||||||||
Interest Expense | 42 | 41 | 44 | ||||||||
Depreciation and amortization | 41 | 31 | 28 | ||||||||
Increase in fair value of preferred stock derivative | 15 | ||||||||||
Increase in fair value of preferred stock derivative, after-tax | 10 | ||||||||||
Income Tax Benefit | 44 | $ 11 | (163) | ||||||||
Interest expense on uncertain tax positions | 66 | ||||||||||
Valuation allowances against deferred tax assets | $ 101 | ||||||||||
Corporate and Other [Member] | Tax Settlement [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Income Tax Benefit | $ 43 |
Goodwill - Additional Informati
Goodwill - Additional Information (Detail) - USD ($) | Dec. 31, 2015 | Dec. 31, 2014 |
Goodwill [Line Items] | ||
Goodwill | $ 1,406,000,000 | $ 1,407,000,000 |
Accumulated impairment loss | 12,000,000 | 18,000,000 |
Delmarva Power & Light Co/De [Member] | ||
Goodwill [Line Items] | ||
Goodwill | 8,000,000 | 8,000,000 |
Accumulated impairment loss | $ 0 | $ 0 |
Regulatory Matters - Schedule o
Regulatory Matters - Schedule of Regulatory Assets and Regulatory Liabilities (Detail) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | $ 2,246 | $ 2,409 |
Regulatory Liabilities | 308 | 343 |
Pension and Other Postretirement Benefit Costs [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 910 | 946 |
Securitized Stranded Costs [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 202 | 278 |
Recoverable Income Taxes [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 224 | 274 |
Demand-Side Management Costs [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 403 | 329 |
Smart Grid Costs [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 266 | 261 |
Deferred Energy Supply Costs [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 32 | 73 |
Incremental Storm Restoration Costs [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 43 | 51 |
Deferred Debt Extinguishment Costs [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 36 | 42 |
MAPP Abandonment Costs [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 7 | 33 |
Recoverable Workers' Compensation and Long-Term Disability Costs [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 31 | 30 |
Deferred Losses on Gas Derivatives [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 2 | 4 |
Other Regulatory Assets [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 90 | 88 |
Asset Removal Costs [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Liabilities | 211 | 250 |
Deferred Income Taxes Due to Customers [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Liabilities | 12 | 44 |
Deferred Energy Supply Costs [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Liabilities | 11 | 3 |
Other Regulatory Liabilities [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Liabilities | 29 | 34 |
Federal and State Tax Benefits, Related to Securitized Stranded Costs [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Liabilities | 13 | 8 |
Reserves for FERC ROE Transmission Challenges [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Liabilities | 32 | 4 |
Potomac Electric Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 720 | 697 |
Regulatory Liabilities | 92 | 104 |
Potomac Electric Power Co [Member] | Recoverable Income Taxes [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 142 | 148 |
Potomac Electric Power Co [Member] | Demand-Side Management Costs [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 292 | 238 |
Potomac Electric Power Co [Member] | Smart Grid Costs [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 181 | 175 |
Potomac Electric Power Co [Member] | Deferred Energy Supply Costs [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 3 | 3 |
Potomac Electric Power Co [Member] | Incremental Storm Restoration Costs [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 19 | 29 |
Potomac Electric Power Co [Member] | Deferred Debt Extinguishment Costs [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 19 | 22 |
Potomac Electric Power Co [Member] | MAPP Abandonment Costs [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 4 | 19 |
Potomac Electric Power Co [Member] | Recoverable Workers' Compensation and Long-Term Disability Costs [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 31 | 30 |
Potomac Electric Power Co [Member] | Other Regulatory Assets [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 29 | 33 |
Potomac Electric Power Co [Member] | Asset Removal Costs [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Liabilities | 58 | 84 |
Potomac Electric Power Co [Member] | Deferred Income Taxes Due to Customers [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Liabilities | 6 | 4 |
Potomac Electric Power Co [Member] | Deferred Energy Supply Costs [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Liabilities | 5 | 3 |
Potomac Electric Power Co [Member] | Other Regulatory Liabilities [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Liabilities | 10 | 11 |
Potomac Electric Power Co [Member] | Reserves for FERC ROE Transmission Challenges [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Liabilities | 13 | 2 |
Delmarva Power & Light Co/De [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 308 | 356 |
Regulatory Liabilities | 189 | 225 |
Delmarva Power & Light Co/De [Member] | Recoverable Income Taxes [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 38 | 84 |
Delmarva Power & Light Co/De [Member] | Demand-Side Management Costs [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 111 | 91 |
Delmarva Power & Light Co/De [Member] | Smart Grid Costs [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 85 | 86 |
Delmarva Power & Light Co/De [Member] | Deferred Energy Supply Costs [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 2 | 12 |
Delmarva Power & Light Co/De [Member] | Incremental Storm Restoration Costs [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 6 | 7 |
Delmarva Power & Light Co/De [Member] | Deferred Debt Extinguishment Costs [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 10 | 12 |
Delmarva Power & Light Co/De [Member] | MAPP Abandonment Costs [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 3 | 14 |
Delmarva Power & Light Co/De [Member] | Deferred Losses on Gas Derivatives [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 2 | 4 |
Delmarva Power & Light Co/De [Member] | Other Regulatory Assets [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 38 | 28 |
Delmarva Power & Light Co/De [Member] | COPCO Acquisition Adjustment [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 13 | 18 |
Delmarva Power & Light Co/De [Member] | Asset Removal Costs [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Liabilities | 153 | 166 |
Delmarva Power & Light Co/De [Member] | Deferred Income Taxes Due to Customers [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Liabilities | 3 | 37 |
Delmarva Power & Light Co/De [Member] | Deferred Energy Supply Costs [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Liabilities | 6 | |
Delmarva Power & Light Co/De [Member] | Other Regulatory Liabilities [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Liabilities | 16 | 21 |
Delmarva Power & Light Co/De [Member] | Reserves for FERC ROE Transmission Challenges [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Liabilities | 11 | 1 |
Atlantic City Electric Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 322 | 427 |
Regulatory Liabilities | 27 | 14 |
Atlantic City Electric Co [Member] | Securitized Stranded Costs [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 202 | 278 |
Atlantic City Electric Co [Member] | Recoverable Income Taxes [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 44 | 42 |
Atlantic City Electric Co [Member] | Deferred Energy Supply Costs [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 27 | 58 |
Atlantic City Electric Co [Member] | Incremental Storm Restoration Costs [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 18 | 15 |
Atlantic City Electric Co [Member] | Deferred Debt Extinguishment Costs [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 7 | 8 |
Atlantic City Electric Co [Member] | Other Regulatory Assets [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory assets | 24 | 26 |
Atlantic City Electric Co [Member] | Deferred Income Taxes Due to Customers [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Liabilities | 3 | 3 |
Atlantic City Electric Co [Member] | Other Regulatory Liabilities [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Liabilities | 3 | 2 |
Atlantic City Electric Co [Member] | Federal and State Tax Benefits, Related to Securitized Stranded Costs [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Liabilities | 13 | 8 |
Atlantic City Electric Co [Member] | Reserves for FERC ROE Transmission Challenges [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Liabilities | $ 8 | $ 1 |
Regulatory Matters - Additional
Regulatory Matters - Additional Information (Detail) | Feb. 01, 2016USD ($) | Nov. 06, 2015USD ($) | Sep. 11, 2015USD ($) | Jun. 01, 2015USD ($) | May. 19, 2015USD ($) | Apr. 17, 2015USD ($) | Dec. 08, 2014 | Dec. 07, 2014 | Apr. 15, 2014USD ($) | Sep. 20, 2013USD ($) | Aug. 31, 2015 | Mar. 31, 2015USD ($) | Oct. 31, 2014 | Aug. 31, 2014USD ($) | Jul. 31, 2014USD ($) | May. 31, 2014USD ($) | Dec. 31, 2013USD ($) | Oct. 31, 2013USD ($) | Jul. 31, 2013USD ($) | Mar. 31, 2013USD ($) | Feb. 28, 2013 | Nov. 30, 2012USD ($) | Jul. 31, 2012USD ($) | Dec. 31, 2011USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2011 | Dec. 31, 2015USD ($) | Apr. 30, 2012MW |
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||||||||||||||
Transition bond maturity, lower range | 2,016 | |||||||||||||||||||||||||||
Transition bond maturity, upper range | 2,023 | |||||||||||||||||||||||||||
Date of acquisition | Apr. 29, 2014 | |||||||||||||||||||||||||||
Return on equity, percentage | 10.00% | 9.36% | 10.75% | |||||||||||||||||||||||||
Approved rate change | $ 8,750,000 | $ 27,900,000 | $ 18,100,000 | |||||||||||||||||||||||||
Return on equity, percentage | 9.62% | 9.31% | ||||||||||||||||||||||||||
Effect of proposed change on Gas Cost Rate | 26.00% | |||||||||||||||||||||||||||
Adjusted rate change | $ 37,400,000 | |||||||||||||||||||||||||||
Charges on cost of recovery | $ 24,000,000 | |||||||||||||||||||||||||||
Consolidated tax adjustment calculation review period | 5 years | |||||||||||||||||||||||||||
Percentage of revenue requirement related to consolidated tax adjustment calculation | 25.00% | |||||||||||||||||||||||||||
Basis-point | 0.50% | |||||||||||||||||||||||||||
Return of equity effective date | Mar. 8, 2016 | |||||||||||||||||||||||||||
New power plant output | MW | 661 | |||||||||||||||||||||||||||
Undergrounding project cost | $ 1,000,000,000 | |||||||||||||||||||||||||||
Entity share to complete project | 500,000,000 | |||||||||||||||||||||||||||
Federal Energy Regulatory Commission Return On Equity Complaint [Member] | ||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||||||||||||||
Return on equity, percentage | 8.80% | 10.80% | ||||||||||||||||||||||||||
Reserve for litigation filed | $ 32,000,000 | $ 32,000,000 | ||||||||||||||||||||||||||
Expected [Member] | ||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||||||||||||||
Requested rate change | $ 43,300,000 | $ 60,800,000 | $ 68,400,000 | |||||||||||||||||||||||||
Return on equity, percentage | 10.25% | |||||||||||||||||||||||||||
Actual [Member] | ||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||||||||||||||
Adjusted rate change | 66,200,000 | |||||||||||||||||||||||||||
District of Columbia [Member] | DC Undergrounding Task Force [Member] | ||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||||||||||||||
Underground project cost | 375,000,000 | |||||||||||||||||||||||||||
MAPP Abandonment Costs [Member] | ||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||||||||||||||
Project termination costs | Aug. 24, 2012 | |||||||||||||||||||||||||||
Amortization and recovery period | 2016-05 | |||||||||||||||||||||||||||
Minimum [Member] | ||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||||||||||||||
Regulatory asset, amortization period, years | 1 year | |||||||||||||||||||||||||||
New power plant output | MW | 650 | |||||||||||||||||||||||||||
Maximum [Member] | ||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||||||||||||||
Regulatory asset, amortization period, years | 20 years | |||||||||||||||||||||||||||
New power plant output | MW | 700 | |||||||||||||||||||||||||||
Maximum [Member] | District of Columbia [Member] | Department of Transportation [Member] | ||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||||||||||||||
Under grounding project costs covered by existing capital projects program | 125,000,000 | |||||||||||||||||||||||||||
Pepco and Delmarva Power Light Co [Member] | ||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||||||||||||||
Incremental Storm Restoration Costs Amortization and recovery period | 5 years | |||||||||||||||||||||||||||
Delmarva Power & Light Co/De [Member] | ||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||||||||||||||
Requested rate change | $ 39,000,000 | $ 56,000,000 | $ 42,000,000 | |||||||||||||||||||||||||
Return on equity, percentage | 10.00% | 9.70% | 10.25% | 10.80% | ||||||||||||||||||||||||
Approved rate change | $ 15,100,000 | |||||||||||||||||||||||||||
Return on equity, percentage | 9.70% | |||||||||||||||||||||||||||
Increased distribution base period | 4 years | |||||||||||||||||||||||||||
Estimated return on equity, year one | 7.41% | |||||||||||||||||||||||||||
Estimated return on equity, year two | 8.80% | |||||||||||||||||||||||||||
Estimated return on equity, year three | 9.75% | |||||||||||||||||||||||||||
Estimated return on equity, year four | 9.75% | |||||||||||||||||||||||||||
Customer refundable fees | $ 500,000 | |||||||||||||||||||||||||||
Effect of proposed change on Gas Cost Rate | 26.00% | |||||||||||||||||||||||||||
Basis-point | 0.50% | 0.50% | 0.50% | |||||||||||||||||||||||||
Return of equity effective date | Mar. 8, 2016 | |||||||||||||||||||||||||||
Customer refunds | $ 11,900,000 | |||||||||||||||||||||||||||
New power plant output | MW | 661 | |||||||||||||||||||||||||||
Goodwill transferred to a regulatory asset | $ 41,000,000 | $ 41,000,000 | ||||||||||||||||||||||||||
Return earned on regulatory assets | 12.95% | 12.95% | ||||||||||||||||||||||||||
Delmarva Power & Light Co/De [Member] | Federal Energy Regulatory Commission Return On Equity Complaint [Member] | ||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||||||||||||||
Return on equity, percentage | 8.80% | 10.80% | 8.70% | 11.30% | ||||||||||||||||||||||||
Reserve for litigation filed | $ 11,000,000 | $ 11,000,000 | ||||||||||||||||||||||||||
Delmarva Power & Light Co/De [Member] | Minimum [Member] | ||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||||||||||||||
Regulatory asset, amortization period, years | 1 year | |||||||||||||||||||||||||||
New power plant output | MW | 650 | |||||||||||||||||||||||||||
Delmarva Power & Light Co/De [Member] | Minimum [Member] | Federal Energy Regulatory Commission Return On Equity Complaint [Member] | ||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||||||||||||||
Return on equity, percentage | 6.78% | |||||||||||||||||||||||||||
Delmarva Power & Light Co/De [Member] | Maximum [Member] | ||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||||||||||||||
Regulatory asset, amortization period, years | 20 years | |||||||||||||||||||||||||||
New power plant output | MW | 700 | |||||||||||||||||||||||||||
Delmarva Power & Light Co/De [Member] | Maximum [Member] | Federal Energy Regulatory Commission Return On Equity Complaint [Member] | ||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||||||||||||||
Return on equity, percentage | 10.33% | |||||||||||||||||||||||||||
Atlantic City Electric Co [Member] | ||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||||||||||||||
Transition bond maturity, lower range | 2,016 | |||||||||||||||||||||||||||
Transition bond maturity, upper range | 2,023 | |||||||||||||||||||||||||||
Incremental Storm Restoration Costs Amortization and recovery period | 3 years | |||||||||||||||||||||||||||
Requested rate change | $ 33,900,000 | $ 52,000,000 | ||||||||||||||||||||||||||
Return on equity, percentage | 10.00% | 10.80% | ||||||||||||||||||||||||||
Approved rate change | $ 32,600,000 | $ (1,300,000) | $ 33,900,000 | |||||||||||||||||||||||||
Contributions received by ACE | $ 11,000,000 | $ 11,000,000 | ||||||||||||||||||||||||||
Consolidated tax adjustment calculation review period | 5 years | |||||||||||||||||||||||||||
Percentage of revenue requirement related to consolidated tax adjustment calculation | 25.00% | |||||||||||||||||||||||||||
Basis-point | 0.50% | 0.50% | ||||||||||||||||||||||||||
Return of equity effective date | Mar. 8, 2016 | |||||||||||||||||||||||||||
Customer refunds | $ 9,500,000 | |||||||||||||||||||||||||||
Atlantic City Electric Co [Member] | Subsequent Event [Member] | ||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||||||||||||||
Overall annual rate increase as net impact of adjusting charges | $ 8,800,000 | |||||||||||||||||||||||||||
Atlantic City Electric Co [Member] | Federal Energy Regulatory Commission Return On Equity Complaint [Member] | ||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||||||||||||||
Return on equity, percentage | 8.80% | 10.80% | 8.70% | 11.30% | ||||||||||||||||||||||||
Reserve for litigation filed | $ 8,000,000 | $ 8,000,000 | ||||||||||||||||||||||||||
Atlantic City Electric Co [Member] | Minimum [Member] | ||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||||||||||||||
Regulatory asset, amortization period, years | 1 year | |||||||||||||||||||||||||||
Atlantic City Electric Co [Member] | Minimum [Member] | Federal Energy Regulatory Commission Return On Equity Complaint [Member] | ||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||||||||||||||
Return on equity, percentage | 6.78% | |||||||||||||||||||||||||||
Atlantic City Electric Co [Member] | Maximum [Member] | ||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||||||||||||||
Regulatory asset, amortization period, years | 20 years | |||||||||||||||||||||||||||
Contributions paid by ACE | $ 1,000,000 | |||||||||||||||||||||||||||
Atlantic City Electric Co [Member] | Maximum [Member] | Federal Energy Regulatory Commission Return On Equity Complaint [Member] | ||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||||||||||||||
Return on equity, percentage | 10.33% | |||||||||||||||||||||||||||
Potomac Electric Power Co [Member] | ||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||||||||||||||
Requested rate change | $ 68,400,000 | |||||||||||||||||||||||||||
Return on equity, percentage | 10.00% | 9.36% | 10.25% | 10.75% | 10.80% | |||||||||||||||||||||||
Approved rate change | $ 8,750,000 | $ 27,900,000 | $ 18,100,000 | |||||||||||||||||||||||||
Return on equity, percentage | 9.62% | 9.36% | 9.31% | |||||||||||||||||||||||||
Adjusted rate change | $ 37,400,000 | |||||||||||||||||||||||||||
Charges on cost of recovery | $ 24,000,000 | |||||||||||||||||||||||||||
Basis-point | 0.50% | 0.50% | 0.50% | |||||||||||||||||||||||||
Return of equity effective date | Mar. 8, 2016 | |||||||||||||||||||||||||||
Customer refunds | $ 14,200,000 | |||||||||||||||||||||||||||
New power plant output | MW | 661 | |||||||||||||||||||||||||||
Undergrounding project cost | 1,000,000,000 | |||||||||||||||||||||||||||
Entity share to complete project | 500,000,000 | |||||||||||||||||||||||||||
Potomac Electric Power Co [Member] | Federal Energy Regulatory Commission Return On Equity Complaint [Member] | ||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||||||||||||||
Return on equity, percentage | 8.80% | 10.80% | 8.70% | 11.30% | ||||||||||||||||||||||||
Reserve for litigation filed | $ 13,000,000 | $ 13,000,000 | ||||||||||||||||||||||||||
Potomac Electric Power Co [Member] | Expected [Member] | ||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||||||||||||||
Requested rate change | $ 43,300,000 | $ 60,800,000 | ||||||||||||||||||||||||||
Return on equity, percentage | 10.25% | |||||||||||||||||||||||||||
Potomac Electric Power Co [Member] | Actual [Member] | ||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||||||||||||||
Adjusted rate change | $ 66,200,000 | |||||||||||||||||||||||||||
Potomac Electric Power Co [Member] | District of Columbia [Member] | DC Undergrounding Task Force [Member] | ||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||||||||||||||
Underground project cost | 375,000,000 | |||||||||||||||||||||||||||
Potomac Electric Power Co [Member] | Minimum [Member] | ||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||||||||||||||
Regulatory asset, amortization period, years | 1 year | |||||||||||||||||||||||||||
New power plant output | MW | 650 | |||||||||||||||||||||||||||
Potomac Electric Power Co [Member] | Minimum [Member] | Federal Energy Regulatory Commission Return On Equity Complaint [Member] | ||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||||||||||||||
Return on equity, percentage | 6.78% | |||||||||||||||||||||||||||
Potomac Electric Power Co [Member] | Maximum [Member] | ||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||||||||||||||
Regulatory asset, amortization period, years | 20 years | |||||||||||||||||||||||||||
New power plant output | MW | 700 | |||||||||||||||||||||||||||
Potomac Electric Power Co [Member] | Maximum [Member] | Federal Energy Regulatory Commission Return On Equity Complaint [Member] | ||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||||||||||||||
Return on equity, percentage | 10.33% | |||||||||||||||||||||||||||
Potomac Electric Power Co [Member] | Maximum [Member] | District of Columbia [Member] | Department of Transportation [Member] | ||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||||||||||||||
Under grounding project costs covered by existing capital projects program | $ 125,000,000 |
Property, Plant and Equipment -
Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Detail) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Property, Plant and Equipment [Line Items] | ||
Original Cost | $ 16,218 | $ 15,465 |
Accumulated Depreciation | 4,914 | 4,959 |
Net Book Value | 11,304 | 10,506 |
Potomac Electric Power Co [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Original Cost | 8,091 | 7,764 |
Accumulated Depreciation | 2,799 | 2,816 |
Net Book Value | 5,292 | 4,948 |
Delmarva Power & Light Co/De [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Original Cost | 4,209 | 3,946 |
Accumulated Depreciation | 1,046 | 1,021 |
Net Book Value | 3,163 | 2,925 |
Atlantic City Electric Co [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Original Cost | 3,305 | 3,073 |
Accumulated Depreciation | 764 | 760 |
Net Book Value | 2,541 | 2,313 |
Generation [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Original Cost | 23 | 104 |
Accumulated Depreciation | 19 | 100 |
Net Book Value | 4 | 4 |
Generation [Member] | Atlantic City Electric Co [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Original Cost | 10 | |
Accumulated Depreciation | 9 | |
Net Book Value | 1 | |
Distribution [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Original Cost | 10,051 | 9,527 |
Accumulated Depreciation | 3,161 | 3,021 |
Net Book Value | 6,890 | 6,506 |
Distribution [Member] | Potomac Electric Power Co [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Original Cost | 5,996 | 5,668 |
Accumulated Depreciation | 2,199 | 2,082 |
Net Book Value | 3,797 | 3,586 |
Distribution [Member] | Delmarva Power & Light Co/De [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Original Cost | 2,043 | 1,928 |
Accumulated Depreciation | 490 | 489 |
Net Book Value | 1,553 | 1,439 |
Distribution [Member] | Atlantic City Electric Co [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Original Cost | 2,012 | 1,931 |
Accumulated Depreciation | 472 | 450 |
Net Book Value | 1,540 | 1,481 |
Transmission [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Original Cost | 3,554 | 3,252 |
Accumulated Depreciation | 962 | 934 |
Net Book Value | 2,592 | 2,318 |
Transmission [Member] | Potomac Electric Power Co [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Original Cost | 1,378 | 1,306 |
Accumulated Depreciation | 475 | 463 |
Net Book Value | 903 | 843 |
Transmission [Member] | Delmarva Power & Light Co/De [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Original Cost | 1,208 | 1,107 |
Accumulated Depreciation | 259 | 248 |
Net Book Value | 949 | 859 |
Transmission [Member] | Atlantic City Electric Co [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Original Cost | 968 | 839 |
Accumulated Depreciation | 228 | 223 |
Net Book Value | 740 | 616 |
Construction Work in Progress [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Original Cost | 604 | 688 |
Net Book Value | 604 | 688 |
Construction Work in Progress [Member] | Potomac Electric Power Co [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Original Cost | 318 | 312 |
Net Book Value | 318 | 312 |
Construction Work in Progress [Member] | Delmarva Power & Light Co/De [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Original Cost | 107 | 125 |
Net Book Value | 107 | 125 |
Construction Work in Progress [Member] | Atlantic City Electric Co [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Original Cost | 158 | 115 |
Net Book Value | 158 | 115 |
Non-Operating and Other Property [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Original Cost | 1,440 | 1,383 |
Accumulated Depreciation | 609 | 751 |
Net Book Value | 831 | 632 |
Non-Operating and Other Property [Member] | Potomac Electric Power Co [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Original Cost | 399 | 478 |
Accumulated Depreciation | 125 | 271 |
Net Book Value | 274 | 207 |
Non-Operating and Other Property [Member] | Delmarva Power & Light Co/De [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Original Cost | 305 | 275 |
Accumulated Depreciation | 134 | 131 |
Net Book Value | 171 | 144 |
Non-Operating and Other Property [Member] | Atlantic City Electric Co [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Original Cost | 167 | 178 |
Accumulated Depreciation | 64 | 78 |
Net Book Value | 103 | 100 |
Gas [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Original Cost | 546 | 511 |
Accumulated Depreciation | 163 | 153 |
Net Book Value | 383 | 358 |
Gas [Member] | Delmarva Power & Light Co/De [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Original Cost | 546 | 511 |
Accumulated Depreciation | 163 | 153 |
Net Book Value | $ 383 | $ 358 |
Property, Plant and Equipment60
Property, Plant and Equipment - Additional Information (Detail) | Nov. 10, 2015USD ($) | Oct. 16, 2015USD ($)a | Jul. 02, 2015USD ($)a | Dec. 31, 2015USD ($)a | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) |
Property, Plant and Equipment [Line Items] | ||||||
Present value of future minimum lease payments | $ 152,000,000 | |||||
Semi-annual payments | $ 8,000,000 | |||||
Description of lease term | Over a 25-year period that began in December 1994 | |||||
Guaranteed residual value due at end of lease term | $ 1 | |||||
Approximate annual commitments, 2016 | 15,000,000 | |||||
Approximate annual commitments, 2017 | 15,000,000 | |||||
Approximate annual commitments, 2018 | 15,000,000 | |||||
Approximate annual commitments, 2019 | $ 16,000,000 | |||||
Impairment losses | $ 81,000,000 | $ 4,000,000 | ||||
Long lived assets after impairment, carrying amount | $ 2,000,000 | |||||
Percentage of change in the estimated cash flows | 10.00% | |||||
Percentage of change in discount rate assumptions | 1.00% | |||||
Minimum [Member] | ||||||
Property, Plant and Equipment [Line Items] | ||||||
Range of discount rates | 10.00% | |||||
Maximum [Member] | ||||||
Property, Plant and Equipment [Line Items] | ||||||
Range of discount rates | 16.00% | |||||
Pepco Energy Services [Member] | ||||||
Property, Plant and Equipment [Line Items] | ||||||
Impairment losses | $ 81,000,000 | |||||
Impairment losses, after-tax | 48,000,000 | |||||
Long-lived assets before impairment, carrying amount | 83,000,000 | |||||
Buzzard Point [Member] | ||||||
Property, Plant and Equipment [Line Items] | ||||||
Area of land held as non-utility property | a | 3.5 | |||||
Carrying value of land | $ 2,000,000 | |||||
Sale price of land | $ 39,000,000 | |||||
Gain on sale of land before tax | $ 37,000,000 | |||||
Gain on sale of land after tax | 22,000,000 | |||||
No Ma [Member] | ||||||
Property, Plant and Equipment [Line Items] | ||||||
Area of land held as non-utility property | a | 3.8 | 1.8 | ||||
Carrying value remaining portion of land | $ 4,000,000 | |||||
Sale price of remaining portion of land | $ 13,000,000 | |||||
Period to purchase remaining portion of land | 90 days | |||||
No Ma [Member] | Third Party Sale Agreement [Member] | ||||||
Property, Plant and Equipment [Line Items] | ||||||
Area of land held as non-utility property | a | 2 | |||||
Carrying value of land | $ 5,000,000 | |||||
Sale price of land | $ 14,000,000 | |||||
Gain on sale of land before tax | $ 9,000,000 | |||||
Gain on sale of land after tax | 5,000,000 | |||||
Subsidiaries [Member] | ||||||
Property, Plant and Equipment [Line Items] | ||||||
Jointly owned plant, net book value ownership | 16,000,000 | 15,000,000 | ||||
Impairment losses | 4,000,000 | |||||
Impairment losses, after-tax | $ 3,000,000 | |||||
Potomac Electric Power Co [Member] | ||||||
Property, Plant and Equipment [Line Items] | ||||||
Present value of future minimum lease payments | 152,000,000 | |||||
Semi-annual payments | $ 8,000,000 | |||||
Description of lease term | Over a 25-year period that began in December 1994 | |||||
Guaranteed residual value due at end of lease term | $ 1 | |||||
Approximate annual commitments, 2016 | 15,000,000 | |||||
Approximate annual commitments, 2017 | 15,000,000 | |||||
Approximate annual commitments, 2018 | 15,000,000 | |||||
Approximate annual commitments, 2019 | $ 16,000,000 | |||||
Potomac Electric Power Co [Member] | Buzzard Point [Member] | ||||||
Property, Plant and Equipment [Line Items] | ||||||
Area of land held as non-utility property | a | 3.5 | |||||
Carrying value of land | $ 2,000,000 | |||||
Sale price of land | $ 39,000,000 | |||||
Gain on sale of land before tax | 37,000,000 | |||||
Gain on sale of land after tax | $ 22,000,000 | |||||
Potomac Electric Power Co [Member] | No Ma [Member] | ||||||
Property, Plant and Equipment [Line Items] | ||||||
Area of land held as non-utility property | a | 1.8 | |||||
Carrying value remaining portion of land | $ 4,000,000 | |||||
Sale price of remaining portion of land | $ 13,000,000 | |||||
Period to purchase remaining portion of land | 90 days | |||||
Potomac Electric Power Co [Member] | No Ma [Member] | Third Party Sale Agreement [Member] | ||||||
Property, Plant and Equipment [Line Items] | ||||||
Area of land held as non-utility property | a | 2 | |||||
Carrying value of land | $ 5,000,000 | |||||
Sale price of land | $ 14,000,000 | |||||
Gain on sale of land before tax | $ 9,000,000 | |||||
Gain on sale of land after tax | 5,000,000 | |||||
Conectiv Energy [Member] | ||||||
Property, Plant and Equipment [Line Items] | ||||||
Asset retirement obligation | 7,000,000 | |||||
Atlantic City Electric Co [Member] | ||||||
Property, Plant and Equipment [Line Items] | ||||||
Jointly owned plant, net book value ownership | $ 11,000,000 | $ 11,000,000 |
Property, Plant and Equipment61
Property, Plant and Equipment - Capital Lease Assets Recorded within Property, Plant and Equipment (Detail) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Capital Leased Assets [Line Items] | ||
Original Cost | $ 152 | $ 152 |
Accumulated Amortization | 102 | 92 |
Net Book Value | 50 | 60 |
Transmission [Member] | ||
Capital Leased Assets [Line Items] | ||
Original Cost | 76 | 76 |
Accumulated Amortization | 51 | 46 |
Net Book Value | 25 | 30 |
Distribution [Member] | ||
Capital Leased Assets [Line Items] | ||
Original Cost | 76 | 76 |
Accumulated Amortization | 51 | 46 |
Net Book Value | $ 25 | $ 30 |
Pension and Other Postretirem62
Pension and Other Postretirement Benefits - Schedule of Changes in Benefit Obligations and Plan Assets (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Pension Benefits [Member] | |||
Change in Benefit Obligation | |||
Service cost | $ 57 | $ 44 | $ 53 |
Interest cost | 109 | 109 | 100 |
Change in Plan Assets | |||
Fair value of plan assets at beginning of year | 1,557 | ||
Fair value of plan assets at end of year | 1,397 | 1,557 | |
Pension Benefits [Member] | Investments Measured at Fair Value [Member] | |||
Change in Benefit Obligation | |||
Benefit obligation at beginning of year | 2,638 | 2,238 | |
Service cost | 57 | 44 | |
Interest cost | 109 | 109 | |
Actuarial loss (gain) | (151) | 401 | |
Benefits paid | (163) | (154) | |
Benefit obligation at end of year | 2,490 | 2,638 | 2,238 |
Change in Plan Assets | |||
Fair value of plan assets at beginning of year | 2,236 | 2,116 | |
Actual return on plan assets | (61) | 268 | |
Company and participant contributions | 6 | 6 | |
Benefits paid by plan | (163) | (154) | |
Fair value of plan assets at end of year | 2,018 | 2,236 | 2,116 |
Funded Status at end of year (plan assets less plan obligations) | (472) | (402) | |
Other Postretirement Benefits [Member] | |||
Change in Benefit Obligation | |||
Service cost | 7 | 7 | 8 |
Interest cost | 24 | 26 | 29 |
Change in Plan Assets | |||
Fair value of plan assets at beginning of year | 340 | ||
Fair value of plan assets at end of year | 326 | 340 | |
Other Postretirement Benefits [Member] | Investments Measured at Fair Value [Member] | |||
Change in Benefit Obligation | |||
Benefit obligation at beginning of year | 632 | 574 | |
Service cost | 7 | 7 | |
Interest cost | 24 | 26 | |
Actuarial loss (gain) | (61) | 59 | |
Benefits paid | (39) | (34) | |
Benefit obligation at end of year | 563 | 632 | 574 |
Change in Plan Assets | |||
Fair value of plan assets at beginning of year | 367 | 368 | |
Actual return on plan assets | 1 | 21 | |
Company and participant contributions | 5 | 6 | |
Benefits paid by plan | (25) | (28) | |
Fair value of plan assets at end of year | 348 | 367 | $ 368 |
Funded Status at end of year (plan assets less plan obligations) | $ (215) | $ (265) |
Pension and Other Postretirem63
Pension and Other Postretirement Benefits - Additional Information (Detail) | Jul. 01, 2013 | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($)Amendments | Dec. 31, 2012USD ($) |
Defined Benefit Plan Disclosure [Line Items] | |||||
Accumulated benefit obligation | $ 2,300,000,000 | $ 2,400,000,000 | |||
Service periods for participating employee | 11 years | 11 years | |||
Unfunded capital commitments | $ 9,000,000 | $ 11,000,000 | |||
Pension contribution | $ 120,000,000 | ||||
Percentage of participants vested | 100.00% | ||||
Defined contribution plan matching contributions | $ 14,000,000 | 13,000,000 | 12,000,000 | ||
Pension and other postretirement net periodic benefit cost | 97,000,000 | 58,000,000 | 95,000,000 | ||
Other postretirement benefit obligations | 215,000,000 | 265,000,000 | |||
Pension Benefits [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Net loss to be amortized from AOCL or regulatory assets into net periodic benefit cost | 63,000,000 | ||||
Prior service cost to be amortized from AOCL or regulatory assets into net periodic benefit cost | $ 7,000,000 | ||||
Percentage of plan asset target allocation | 68.00% | ||||
Pension and other postretirement net periodic benefit cost | $ 93,000,000 | 59,000,000 | 77,000,000 | ||
Other Postretirement Benefits [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Net loss to be amortized from AOCL or regulatory assets into net periodic benefit cost | 1,000,000 | ||||
Prior service cost to be amortized from AOCL or regulatory assets into net periodic benefit cost | 13,000,000 | ||||
OPEB contributions | 2,000,000 | 1,000,000 | |||
Pension and other postretirement net periodic benefit cost | 4,000,000 | (1,000,000) | 18,000,000 | ||
Other postretirement benefit obligations | 215,000,000 | 265,000,000 | |||
Potomac Electric Power Co [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Pension contribution | 0 | 0 | 0 | ||
Pension and other postretirement net periodic benefit cost | 30,000,000 | 22,000,000 | $ 34,000,000 | ||
Prepaid pension expense | 291,000,000 | 316,000,000 | |||
Other postretirement benefit obligations | 49,000,000 | 57,000,000 | |||
Potomac Electric Power Co [Member] | Other Postretirement Benefits [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Number of amendments, PHI approved | Amendments | 2 | ||||
Reduction in net periodic benefit cost | $ 7,000,000 | ||||
Percentage of postretirement benefit costs | 40.00% | ||||
OPEB contributions | 2,000,000 | $ 1,000,000 | $ 6,000,000 | ||
Delmarva Power & Light Co/De [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Pension contribution | 0 | 0 | 10,000,000 | ||
Pension and other postretirement net periodic benefit cost | 15,000,000 | 7,000,000 | $ 18,000,000 | ||
Prepaid pension expense | 205,000,000 | 220,000,000 | |||
Other postretirement benefit obligations | 19,000,000 | 21,000,000 | |||
Delmarva Power & Light Co/De [Member] | Other Postretirement Benefits [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Number of amendments, PHI approved | Amendments | 2 | ||||
Reduction in net periodic benefit cost | 4,000,000 | ||||
OPEB contributions | 0 | 0 | $ 3,000,000 | ||
Delmarva Power & Light Co/De [Member] | Retiree [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Pension contribution | 0 | 0 | |||
PHI Service Company [Member] | Other Postretirement Benefits [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Number of amendments, PHI approved | Amendments | 2 | ||||
Reduction in net periodic benefit cost | $ 193,000,000 | $ 69,000,000 | |||
Prior service credit included in projected benefit obligation | $ 124,000,000 | ||||
Amortization period | 10 years | ||||
Change in the discount rate | 4.95% | 4.10% | |||
Reduction of the projected benefit obligation | $ 19,000,000 | ||||
Percentage of postretirement benefit costs | 36.00% | ||||
PHI Service Company [Member] | Retiree [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Pension contribution | 0 | $ 0 | |||
Atlantic City Electric Co [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Pension contribution | 0 | 0 | $ 30,000,000 | ||
Pension and other postretirement net periodic benefit cost | 15,000,000 | 13,000,000 | $ 17,000,000 | ||
Prepaid pension expense | 83,000,000 | 96,000,000 | |||
Other postretirement benefit obligations | 33,000,000 | 36,000,000 | |||
Atlantic City Electric Co [Member] | Other Postretirement Benefits [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Number of amendments, PHI approved | Amendments | 2 | ||||
Reduction in net periodic benefit cost | $ 3,000,000 | ||||
Percentage of postretirement benefit costs | 45.00% | ||||
OPEB contributions | 3,000,000 | $ 3,000,000 | $ 6,000,000 | ||
Atlantic City Electric Co [Member] | Retiree [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Pension contribution | 0 | 0 | |||
Subsidiaries [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Pension and other postretirement net periodic benefit cost | 37,000,000 | 16,000,000 | $ 26,000,000 | ||
Subsidiaries [Member] | Other Postretirement Benefits [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
OPEB contributions | $ 0 | $ 0 |
Pension and Other Postretirem64
Pension and Other Postretirement Benefits - Amounts Recognized in Consolidated Balance Sheets (Detail) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Regulatory asset | $ 2,246 | $ 2,409 | ||
Current liabilities | (2,308) | (2,056) | ||
Pension benefit obligation | (466) | (396) | ||
Other postretirement benefit obligations | (215) | (265) | ||
Deferred income tax liabilities | (3,393) | (3,242) | ||
Deferred income tax liabilities | 15 | 17 | ||
Accumulated other comprehensive loss, net of tax | 36 | 46 | $ 34 | $ 48 |
Pension Benefits [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Regulatory asset | 870 | 871 | ||
Current liabilities | (6) | (6) | ||
Pension benefit obligation | (466) | (396) | ||
Deferred income tax liabilities | (162) | (193) | ||
Accumulated other comprehensive loss, net of tax | 28 | 37 | ||
Net amount recorded | 264 | 313 | ||
Other Postretirement Benefits [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Regulatory asset | 40 | 75 | ||
Other postretirement benefit obligations | (215) | (265) | ||
Deferred income tax liabilities | 70 | 77 | ||
Net amount recorded | $ (105) | $ (113) |
Pension and Other Postretirem65
Pension and Other Postretirement Benefits - Schedule of Amounts Included in AOCL and Regulatory Assets (Detail) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Regulatory assets | $ 2,246 | $ 2,409 |
Pension Benefits [Member] | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Unrecognized net actuarial loss | 910 | 925 |
Unamortized prior service cost (credit) | 6 | 8 |
Total | 916 | 933 |
Accumulated other comprehensive loss ($28 million and $37 million, net of tax, at December 31, 2015 and 2014, respectively) | 46 | 62 |
Regulatory assets | 870 | 871 |
Total | 916 | 933 |
Other Postretirement Benefits [Member] | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Unrecognized net actuarial loss | 128 | 176 |
Unamortized prior service cost (credit) | (88) | (101) |
Total | 40 | 75 |
Regulatory assets | 40 | 75 |
Total | $ 40 | $ 75 |
Pension and Other Postretirem66
Pension and Other Postretirement Benefits - Schedule of Amounts Included in AOCL and Regulatory Assets (Parenthetical) (Detail) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Accumulated other comprehensive loss, net of tax | $ 36 | $ 46 | $ 34 | $ 48 |
Pension Benefits [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Accumulated other comprehensive loss, net of tax | $ 28 | $ 37 |
Pension and Other Postretirem67
Pension and Other Postretirement Benefits - Changes in Plan Assets and Benefit Obligations Recognized in AOCL and Regulatory Assets (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Pension Benefits [Member] | |||
Amounts amortized during the year: | |||
Amortization of prior service (cost) credit | $ (2) | $ (2) | $ (2) |
Amortization of net actuarial loss | (65) | (45) | (67) |
Amounts arising during the year: | |||
Current year prior service cost (credit) | 3 | ||
Current year actuarial loss (gain) | 50 | 276 | (218) |
Total recognized in AOCL and Regulatory assets for the year ended December 31 | (17) | 229 | (284) |
Other Postretirement Benefits [Member] | |||
Amounts amortized during the year: | |||
Amortization of prior service (cost) credit | 13 | 13 | 11 |
Amortization of net actuarial loss | (8) | (3) | (12) |
Amounts arising during the year: | |||
Current year prior service cost (credit) | (124) | ||
Current year actuarial loss (gain) | (39) | 62 | (109) |
Total recognized in AOCL and Regulatory assets for the year ended December 31 | $ (34) | $ 72 | $ (234) |
Pension and Other Postretirem68
Pension and Other Postretirement Benefits - Components of Net Periodic Benefit Costs (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Defined Benefit Plan Disclosure [Line Items] | |||
Net periodic benefit cost | $ 97 | $ 58 | $ 95 |
Pension Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service cost | 57 | 44 | 53 |
Interest cost | 109 | 109 | 100 |
Expected return on plan assets | (140) | (141) | (145) |
Amortization of prior service cost (credit) | 2 | 2 | 2 |
Amortization of net actuarial loss | 65 | 45 | 67 |
Net periodic benefit cost | 93 | 59 | 77 |
Other Postretirement Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service cost | 7 | 7 | 8 |
Interest cost | 24 | 26 | 29 |
Expected return on plan assets | (22) | (24) | (20) |
Amortization of prior service cost (credit) | (13) | (13) | (11) |
Amortization of net actuarial loss | 8 | 3 | 12 |
Net periodic benefit cost | $ 4 | $ (1) | $ 18 |
Pension and Other Postretirem69
Pension and Other Postretirement Benefits - Split of Combined Pension and Other Postretirement Net Periodic Benefit Costs (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Net Periodic Benefit Cost | $ 97 | $ 58 | $ 95 |
Potomac Electric Power Co [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Net Periodic Benefit Cost | 30 | 22 | 34 |
Delmarva Power & Light Co/De [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Net Periodic Benefit Cost | 15 | 7 | 18 |
Atlantic City Electric Co [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Net Periodic Benefit Cost | 15 | 13 | 17 |
Subsidiaries [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Net Periodic Benefit Cost | $ 37 | $ 16 | $ 26 |
Pension and Other Postretirem70
Pension and Other Postretirement Benefits - Weighted Average Assumptions Used to Determine Benefit Obligations (Detail) | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Pension Benefits [Member] | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Discount rate | 4.65% | 4.20% |
Rate of compensation increase | 5.00% | 5.00% |
Other Postretirement Benefits [Member] | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Discount rate | 4.55% | 4.15% |
Rate of compensation increase | 5.00% | 5.00% |
Rate to which the cost trend rate is assumed to decline for all eligible retirees (the ultimate trend rate) | 5.00% | 5.00% |
Year that the cost trend rate reaches the ultimate trend rate | 2,020 | 2,020 |
Other Postretirement Benefits [Member] | Pre 65 [Member] | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Health care cost trend rate assumed for current year | 6.33% | 6.67% |
Other Postretirement Benefits [Member] | Post 65 [Member] | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Health care cost trend rate assumed for current year | 5.40% | 5.50% |
Pension and Other Postretirem71
Pension and Other Postretirement Benefits - Weighted Average Assumptions Used to Determine Benefit Obligations (Parenthetical) (Detail) | Dec. 31, 2015 |
Qualified Pension Plans [Member] | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Discount rate | 4.65% |
Non Qualified Pension Plans [Member] | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Discount rate | 4.55% |
Pension and Other Postretirem72
Pension and Other Postretirement Benefits - Summary of Effect of One Percent Change in Assumed Health Care Cost (Detail) $ in Millions | 12 Months Ended |
Dec. 31, 2015USD ($) | |
Compensation and Retirement Disclosure [Abstract] | |
Effect of one percentage point increase in total service and interest cost | $ 1 |
Effect of one percentage point increase in postretirement benefit obligation | 15 |
Effect of one percentage point decrease in total service and interest cost | (1) |
Effect of one percentage point decrease in postretirement benefit obligation | $ (18) |
Pension and Other Postretirem73
Pension and Other Postretirement Benefits - Weighted Average Assumptions Used to Determine Net Periodic Benefit Costs (Detail) | Jul. 01, 2013 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Pension Benefits [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Discount rate | 4.20% | 5.05% | 4.15% | |
Expected long-term return on plan assets | 6.50% | 7.00% | 7.00% | |
Rate of compensation increase | 5.00% | 5.00% | 5.00% | |
Other Postretirement Benefits [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Discount rate | 4.95% | 4.15% | 5.00% | 4.10% |
Expected long-term return on plan assets | 6.75% | 7.25% | 7.00% | |
Rate of compensation increase | 5.00% | 5.00% | 5.00% | |
Health care cost trend rate | 6.67% | 7.00% | 7.50% |
Pension and Other Postretirem74
Pension and Other Postretirement Benefits - Weighted Average Assumptions Used to Determine Net Periodic Benefit Costs (Parenthetical) (Detail) | Jul. 01, 2013 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Other Postretirement Benefits [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Updated discount rate | 4.95% | 4.15% | 5.00% | 4.10% |
Pension and Other Postretirem75
Pension and Other Postretirement Benefits - Summary of Plan Asset Allocations (Detail) | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Retirement Plan [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Plan Assets, Equity | 28.00% | 28.00% |
Plan Assets, Fixed Income | 66.00% | 65.00% |
Plan Assets, Other | 6.00% | 7.00% |
Plan Assets, Total | 100.00% | 100.00% |
Target Plan Asset Allocation, Equity | 27.00% | 27.00% |
Target Plan Asset Allocation, Fixed Income | 68.00% | 68.00% |
Target Plan Asset Allocation, Other | 5.00% | 5.00% |
Target Plan Asset Allocation, Total | 100.00% | 100.00% |
Other Postretirement Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Plan Assets, Equity | 63.00% | 64.00% |
Plan Assets, Fixed Income | 34.00% | 34.00% |
Plan Assets, Cash | 3.00% | 2.00% |
Plan Assets, Total | 100.00% | 100.00% |
Target Plan Asset Allocation, Equity | 60.00% | 60.00% |
Target Plan Asset Allocation, Fixed Income | 35.00% | 35.00% |
Target Plan Asset Allocation, Cash | 5.00% | 5.00% |
Target Plan Asset Allocation, Total | 100.00% | 100.00% |
Pension and Other Postretirem76
Pension and Other Postretirement Benefits - Schedule of Fair Value of Plan Assets (Detail) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Pension Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | $ 1,397 | $ 1,557 | |
Pension Benefits [Member] | Equity Securities Domestic [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 311 | 341 | |
Pension Benefits [Member] | Equity Securities International [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 216 | 255 | |
Pension Benefits [Member] | Fixed Income [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 820 | 916 | |
Pension Benefits [Member] | Cash Equivalents [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 50 | 45 | |
Other Postretirement Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 326 | 340 | |
Other Postretirement Benefits [Member] | Equity Securities Domestic [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 197 | 208 | |
Other Postretirement Benefits [Member] | Fixed Income [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 120 | 126 | |
Other Postretirement Benefits [Member] | Cash Equivalents [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 9 | 6 | |
Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Pension Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 385 | 427 | |
Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Pension Benefits [Member] | Equity Securities Domestic [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 120 | 128 | |
Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Pension Benefits [Member] | Equity Securities International [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 215 | 254 | |
Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Pension Benefits [Member] | Cash Equivalents [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 50 | 45 | |
Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Other Postretirement Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 326 | 340 | |
Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Other Postretirement Benefits [Member] | Equity Securities Domestic [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 197 | 208 | |
Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Other Postretirement Benefits [Member] | Fixed Income [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 120 | 126 | |
Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Other Postretirement Benefits [Member] | Cash Equivalents [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 9 | 6 | |
Significant Other Observable Inputs (Level 2) [Member] | Pension Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 1,001 | 1,118 | |
Significant Other Observable Inputs (Level 2) [Member] | Pension Benefits [Member] | Equity Securities Domestic [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 191 | 213 | |
Significant Other Observable Inputs (Level 2) [Member] | Pension Benefits [Member] | Fixed Income [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 810 | 905 | |
Significant Unobservable Inputs (Level 3) [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 11 | 12 | $ 12 |
Significant Unobservable Inputs (Level 3) [Member] | Fixed Income [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 10 | 11 | 11 |
Significant Unobservable Inputs (Level 3) [Member] | Equity Securities [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 1 | 1 | 1 |
Significant Unobservable Inputs (Level 3) [Member] | Pension Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 11 | 12 | |
Significant Unobservable Inputs (Level 3) [Member] | Pension Benefits [Member] | Equity Securities International [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 1 | 1 | |
Significant Unobservable Inputs (Level 3) [Member] | Pension Benefits [Member] | Fixed Income [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 10 | 11 | |
Investments Measured at Fair Value [Member] | Pension Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 2,018 | 2,236 | 2,116 |
Investments Measured at Fair Value [Member] | Pension Benefits [Member] | Equity Securities Domestic [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 33 | 35 | |
Investments Measured at Fair Value [Member] | Pension Benefits [Member] | Fixed Income [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 504 | 543 | |
Investments Measured at Fair Value [Member] | Pension Benefits [Member] | Private Equity [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 38 | 47 | |
Investments Measured at Fair Value [Member] | Pension Benefits [Member] | Real Estate [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 46 | 54 | |
Investments Measured at Fair Value [Member] | Other Postretirement Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 348 | 367 | $ 368 |
Investments Measured at Fair Value [Member] | Other Postretirement Benefits [Member] | Equity Securities [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | $ 22 | $ 27 |
Pension and Other Postretirem77
Pension and Other Postretirement Benefits - Reconciliation of Fair Value Measurements Using Significant Unobservable Inputs (Detail) - Significant Unobservable Inputs (Level 3) [Member] - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets at beginning of year | $ 12 | $ 12 |
Transfer in (out) of Level 3 | 0 | 0 |
Purchases | 0 | 0 |
Sales | 0 | 0 |
Settlements | (1) | |
Unrealized gain (loss) | 0 | 0 |
Realized gain | 0 | 0 |
Fair value of plan assets at end of year | 11 | 12 |
Equity Securities [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets at beginning of year | 1 | 1 |
Transfer in (out) of Level 3 | 0 | 0 |
Purchases | 0 | 0 |
Sales | 0 | 0 |
Unrealized gain (loss) | 0 | 0 |
Realized gain | 0 | 0 |
Fair value of plan assets at end of year | 1 | 1 |
Fixed Income [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets at beginning of year | 11 | 11 |
Transfer in (out) of Level 3 | 0 | 0 |
Purchases | 0 | 0 |
Sales | 0 | 0 |
Settlements | (1) | |
Unrealized gain (loss) | 0 | 0 |
Realized gain | 0 | 0 |
Fair value of plan assets at end of year | $ 10 | $ 11 |
Pension and Other Postretirem78
Pension and Other Postretirement Benefits - Schedule of Estimated Benefit Payments (Detail) $ in Millions | Dec. 31, 2015USD ($) |
Pension Benefits [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
2,016 | $ 143 |
2,017 | 143 |
2,018 | 148 |
2,019 | 153 |
2,020 | 158 |
2021 through 2025 | 836 |
Other Postretirement Benefits [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
2,016 | 38 |
2,017 | 38 |
2,018 | 38 |
2,019 | 38 |
2,020 | 38 |
2021 through 2025 | $ 189 |
Debt - Components of Long-Term
Debt - Components of Long-Term Debt (Detail) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Debt Instrument [Line Items] | ||
Debt instrument, carrying value | $ 5,001 | $ 4,817 |
Net unamortized discount | (2) | (10) |
Unamortized debt issuance costs | (49) | (44) |
Current portion of long-term debt | (294) | (366) |
Total net long-term debt | 4,656 | 4,397 |
Total long-term debt | 5,001 | 4,817 |
First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt instrument, carrying value | 4,424 | 3,889 |
Total long-term debt | 4,424 | 3,889 |
Medium-Term Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt instrument, carrying value | 40 | 40 |
Total long-term debt | 40 | 40 |
Unsecured Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt instrument, carrying value | 456 | 806 |
Total long-term debt | 456 | 806 |
Transition Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt instrument, carrying value | 171 | 215 |
Unamortized debt issuance costs | (1) | (1) |
Current portion of long-term debt | (46) | (44) |
Total Net Long-Term Debt | 124 | 170 |
Total long-term debt | $ 171 | 215 |
3.05% Due 2022 [Member] | First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 3.05% | |
Debt instrument maturity date | 2,022 | |
Debt instrument, carrying value | $ 200 | 200 |
Total long-term debt | $ 200 | 200 |
6.20% Due 2022 [Member] | First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 6.20% | |
Debt instrument maturity date | 2,022 | |
Debt instrument, carrying value | $ 110 | 110 |
Total long-term debt | $ 110 | 110 |
3.60% Due 2024 [Member] | First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 3.60% | |
Debt instrument maturity date | 2,024 | |
Debt instrument, carrying value | $ 400 | 400 |
Total long-term debt | $ 400 | 400 |
5.75% Due 2034 [Member] | First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 5.75% | |
Debt instrument maturity date | 2,034 | |
Debt instrument, carrying value | $ 100 | 100 |
Total long-term debt | $ 100 | 100 |
5.40% Due 2035 [Member] | First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 5.40% | |
Debt instrument maturity date | 2,035 | |
Debt instrument, carrying value | $ 175 | 175 |
Total long-term debt | $ 175 | 175 |
6.50% Due 2037 [Member] | First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 6.50% | |
Debt instrument maturity date | 2,037 | |
Debt instrument, carrying value | $ 500 | 500 |
Total long-term debt | $ 500 | 500 |
7.90% Due 2038 [Member] | First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 7.90% | |
Debt instrument maturity date | 2,038 | |
Debt instrument, carrying value | $ 250 | 250 |
Total long-term debt | $ 250 | 250 |
4.15% Due 2043 [Member] | First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 4.15% | |
Debt instrument maturity date | 2,043 | |
Debt instrument, carrying value | $ 450 | 250 |
Total long-term debt | $ 450 | 250 |
4.95% Due 2043 [Member] | First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 4.95% | |
Debt instrument maturity date | 2,043 | |
Debt instrument, carrying value | $ 150 | 150 |
Total long-term debt | 150 | 150 |
4.91% Due 2017 [Member] | Transition Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt instrument, carrying value | 17 | |
Total long-term debt | 17 | |
5.05% Due 2020 [Member] | Transition Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt instrument, carrying value | 39 | 51 |
Total long-term debt | 39 | 51 |
5.55% Due 2023 [Member] | Transition Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt instrument, carrying value | 132 | 147 |
Total long-term debt | $ 132 | 147 |
2.70% Due 2015 [Member] | Unsecured Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 2.70% | |
Debt instrument maturity date | 2,015 | |
Debt instrument, carrying value | 250 | |
Total long-term debt | 250 | |
5.90% Due 2016 [Member] | Unsecured Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 5.90% | |
Debt instrument maturity date | 2,016 | |
Debt instrument, carrying value | $ 190 | 190 |
Total long-term debt | $ 190 | 190 |
6.125% Due 2017 [Member] | Unsecured Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 6.125% | |
Debt instrument maturity date | 2,017 | |
Debt instrument, carrying value | $ 81 | 81 |
Total long-term debt | $ 81 | 81 |
7.45% Due 2032 [Member] | Unsecured Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 7.45% | |
Debt instrument maturity date | 2,032 | |
Debt instrument, carrying value | $ 185 | 185 |
Total long-term debt | 185 | 185 |
Atlantic City Electric Co [Member] | ||
Debt Instrument [Line Items] | ||
Debt instrument, carrying value | 1,039 | 904 |
Net unamortized discount | (1) | (1) |
Unamortized debt issuance costs | (6) | (6) |
Current portion of long-term debt | (2) | (15) |
Total net long-term debt | 1,030 | 882 |
Total long-term debt | 1,039 | 904 |
Atlantic City Electric Co [Member] | First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt instrument, carrying value | 1,039 | 904 |
Total long-term debt | 1,039 | 904 |
Atlantic City Electric Co [Member] | Transition Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt instrument, carrying value | 171 | 215 |
Unamortized debt issuance costs | (1) | (1) |
Current portion of long-term debt | (46) | (44) |
Total Net Long-Term Debt | 124 | 170 |
Total long-term debt | $ 171 | 215 |
Atlantic City Electric Co [Member] | 7.68% Due 2015 - 2016 [Member] | First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 7.68% | |
Debt instrument maturity date, start | 2,015 | |
Debt instrument maturity date, end | 2,016 | |
Debt instrument, carrying value | $ 2 | 17 |
Total long-term debt | $ 2 | 17 |
Atlantic City Electric Co [Member] | 7.75% Due 2018 [Member] | First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 7.75% | |
Debt instrument maturity date | 2,018 | |
Debt instrument, carrying value | $ 250 | 250 |
Total long-term debt | $ 250 | 250 |
Atlantic City Electric Co [Member] | 6.80% Due 2021 [Member] | First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 6.80% | |
Debt instrument maturity date | 2,021 | |
Debt instrument, carrying value | $ 39 | 39 |
Total long-term debt | $ 39 | 39 |
Atlantic City Electric Co [Member] | 4.35% Due 2021 [Member] | First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 4.35% | |
Debt instrument maturity date | 2,021 | |
Debt instrument, carrying value | $ 200 | 200 |
Total long-term debt | $ 200 | 200 |
Atlantic City Electric Co [Member] | 3.375% Due 2024 [Member] | First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 3.375% | |
Debt instrument maturity date | 2,024 | |
Debt instrument, carrying value | $ 150 | 150 |
Total long-term debt | $ 150 | 150 |
Atlantic City Electric Co [Member] | 3.50% Due 2025 [Member] | First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 3.50% | |
Debt instrument maturity date | 2,025 | |
Debt instrument, carrying value | $ 150 | |
Total long-term debt | $ 150 | |
Atlantic City Electric Co [Member] | 4.875% Due 2029 [Member] | First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 4.875% | |
Debt instrument maturity date | 2,029 | |
Debt instrument, carrying value | $ 23 | 23 |
Total long-term debt | $ 23 | 23 |
Atlantic City Electric Co [Member] | 5.80% Due 2034 [Member] | First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 5.80% | |
Debt instrument maturity date | 2,034 | |
Debt instrument, carrying value | $ 120 | 120 |
Total long-term debt | $ 120 | 120 |
Atlantic City Electric Co [Member] | 5.80% Due 2036 [Member] | First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 5.80% | |
Debt instrument maturity date | 2,036 | |
Debt instrument, carrying value | $ 105 | 105 |
Total long-term debt | $ 105 | 105 |
Atlantic City Electric Co [Member] | 4.91% Due 2017 [Member] | Transition Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 4.91% | |
Debt instrument maturity date | 2,017 | |
Debt instrument, carrying value | 17 | |
Total long-term debt | 17 | |
Atlantic City Electric Co [Member] | 5.05% Due 2020 [Member] | Transition Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 5.05% | |
Debt instrument maturity date | 2,020 | |
Debt instrument, carrying value | $ 39 | 51 |
Total long-term debt | $ 39 | 51 |
Atlantic City Electric Co [Member] | 5.55% Due 2023 [Member] | Transition Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 5.55% | |
Debt instrument maturity date | 2,023 | |
Debt instrument, carrying value | $ 132 | 147 |
Total long-term debt | $ 132 | 147 |
Atlantic City Electric Co [Member] | 3.5% Due 2025 [Member] | First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 3.50% | |
Debt instrument maturity date | 2,025 | |
Debt instrument, carrying value | $ 150 | |
Total long-term debt | 150 | |
Delmarva Power & Light Co/De [Member] | ||
Debt Instrument [Line Items] | ||
Debt instrument, carrying value | 1,168 | 1,068 |
Net unamortized discount | 2 | 3 |
Unamortized debt issuance costs | (9) | (8) |
Current portion of long-term debt | (100) | (100) |
Total net long-term debt | 1,061 | 963 |
Total long-term debt | 1,168 | 1,068 |
Delmarva Power & Light Co/De [Member] | First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt instrument, carrying value | 1,050 | 850 |
Total long-term debt | 1,050 | 850 |
Delmarva Power & Light Co/De [Member] | Unsecured Tax-Exempt Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt instrument, carrying value | 78 | 78 |
Total long-term debt | 78 | 78 |
Delmarva Power & Light Co/De [Member] | Medium-Term Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt instrument, carrying value | 40 | 40 |
Total long-term debt | $ 40 | 40 |
Delmarva Power & Light Co/De [Member] | Unsecured Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt instrument, carrying value | 100 | |
Total long-term debt | 100 | |
Delmarva Power & Light Co/De [Member] | 5.22% Due 2016 [Member] | First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 5.22% | |
Debt instrument maturity date | 2,016 | |
Debt instrument, carrying value | $ 100 | 100 |
Total long-term debt | $ 100 | 100 |
Delmarva Power & Light Co/De [Member] | 3.50% Due 2023 [Member] | First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 3.50% | |
Debt instrument maturity date | 2,023 | |
Debt instrument, carrying value | $ 500 | 500 |
Total long-term debt | $ 500 | 500 |
Delmarva Power & Light Co/De [Member] | 4.00% Due 2042 [Member] | First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 4.00% | |
Debt instrument maturity date | 2,042 | |
Debt instrument, carrying value | $ 250 | 250 |
Total long-term debt | $ 250 | 250 |
Delmarva Power & Light Co/De [Member] | 4.15% Due 2045 [Member] | First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 4.15% | |
Debt instrument maturity date | 2,045 | |
Debt instrument, carrying value | $ 200 | |
Total long-term debt | $ 200 | |
Delmarva Power & Light Co/De [Member] | 5.40% Due 2031 [Member] | Unsecured Tax-Exempt Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 5.40% | |
Debt instrument maturity date | 2,031 | |
Debt instrument, carrying value | $ 78 | 78 |
Total long-term debt | $ 78 | 78 |
Delmarva Power & Light Co/De [Member] | 7.56% - 7.58% Due 2017 [Member] | Medium-Term Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt instrument maturity date | 2,017 | |
Debt instrument percentage, minimum | 7.56% | |
Debt instrument percentage, maximum | 7.58% | |
Debt instrument, carrying value | $ 14 | 14 |
Total long-term debt | $ 14 | 14 |
Delmarva Power & Light Co/De [Member] | 6.81% Due 2018 [Member] | Medium-Term Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 6.81% | |
Debt instrument maturity date | 2,018 | |
Debt instrument, carrying value | $ 4 | 4 |
Total long-term debt | $ 4 | 4 |
Delmarva Power & Light Co/De [Member] | 7.61% Due 2019 [Member] | Medium-Term Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 7.61% | |
Debt instrument maturity date | 2,019 | |
Debt instrument, carrying value | $ 12 | 12 |
Total long-term debt | $ 12 | 12 |
Delmarva Power & Light Co/De [Member] | 7.72% Due 2027 [Member] | Medium-Term Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 7.72% | |
Debt instrument maturity date | 2,027 | |
Debt instrument, carrying value | $ 10 | 10 |
Total long-term debt | $ 10 | 10 |
Delmarva Power & Light Co/De [Member] | 5.00% Due 2015 [Member] | Unsecured Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 5.00% | |
Debt instrument maturity date | 2,015 | |
Debt instrument, carrying value | $ 0 | 100 |
Total long-term debt | 0 | 100 |
Potomac Electric Power Co [Member] | ||
Debt Instrument [Line Items] | ||
Debt instrument, carrying value | 2,335 | 2,135 |
Net unamortized discount | (3) | (11) |
Unamortized debt issuance costs | (31) | (28) |
Total net long-term debt | 2,301 | 2,096 |
Total long-term debt | $ 2,335 | 2,135 |
Potomac Electric Power Co [Member] | 3.05% Due 2022 [Member] | First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 3.05% | |
Debt instrument maturity date | 2,022 | |
Debt instrument, carrying value | $ 200 | 200 |
Total long-term debt | $ 200 | 200 |
Potomac Electric Power Co [Member] | 6.20% Due 2022 [Member] | First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 6.20% | |
Debt instrument maturity date | 2,022 | |
Debt instrument, carrying value | $ 110 | 110 |
Total long-term debt | $ 110 | 110 |
Potomac Electric Power Co [Member] | 3.60% Due 2024 [Member] | First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 3.60% | |
Debt instrument maturity date | 2,024 | |
Debt instrument, carrying value | $ 400 | 400 |
Total long-term debt | $ 400 | 400 |
Potomac Electric Power Co [Member] | 5.75% Due 2034 [Member] | First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 5.75% | |
Debt instrument maturity date | 2,034 | |
Debt instrument, carrying value | $ 100 | 100 |
Total long-term debt | $ 100 | 100 |
Potomac Electric Power Co [Member] | 5.40% Due 2035 [Member] | First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 5.40% | |
Debt instrument maturity date | 2,035 | |
Debt instrument, carrying value | $ 175 | 175 |
Total long-term debt | $ 175 | 175 |
Potomac Electric Power Co [Member] | 6.50% Due 2037 [Member] | First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 6.50% | |
Debt instrument maturity date | 2,037 | |
Debt instrument, carrying value | $ 500 | 500 |
Total long-term debt | $ 500 | 500 |
Potomac Electric Power Co [Member] | 7.90% Due 2038 [Member] | First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 7.90% | |
Debt instrument maturity date | 2,038 | |
Debt instrument, carrying value | $ 250 | 250 |
Total long-term debt | $ 250 | 250 |
Potomac Electric Power Co [Member] | 4.15% Due 2043 [Member] | First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 4.15% | |
Debt instrument maturity date | 2,043 | |
Debt instrument, carrying value | $ 450 | 250 |
Total long-term debt | $ 450 | 250 |
Potomac Electric Power Co [Member] | 4.95% Due 2043 [Member] | First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest percentage | 4.95% | |
Debt instrument maturity date | 2,043 | |
Debt instrument, carrying value | $ 150 | 150 |
Total long-term debt | $ 150 | 150 |
Pepco Energy Services [Member] | 6.70% - 7.46% Due 2017-2018 [Member] | Secured Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt instrument maturity date, start | 2,015 | |
Debt instrument maturity date, end | 2,018 | |
Debt instrument percentage, minimum | 6.70% | |
Debt instrument percentage, maximum | 7.46% | |
Debt instrument, carrying value | $ 3 | 4 |
Total long-term debt | $ 3 | $ 4 |
Debt - Additional Information (
Debt - Additional Information (Detail) | Jan. 13, 2016USD ($) | Jul. 30, 2015USD ($) | May. 10, 2013USD ($) | Dec. 31, 2015USD ($)Sublimit | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) |
Debt Instrument [Line Items] | ||||||
Debt instrument, carrying value | $ 5,001,000,000 | $ 4,817,000,000 | ||||
Maturities of long term debt, 2016 | 340,000,000 | |||||
Maturities of long term debt, 2017 | 131,000,000 | |||||
Maturities of long term debt, 2018 | 285,000,000 | |||||
Maturities of long term debt, 2019 | 30,000,000 | |||||
Maturities of long term debt, 2020 | 20,000,000 | |||||
Maturities of long term debt, thereafter | 4,366,000,000 | |||||
On-going commercial paper | 875,000,000 | |||||
Short-term debt | 1,063,000,000 | $ 729,000,000 | ||||
Variable rate demand bonds maturing 2017 | 26,000,000 | |||||
Variable rate demand bonds maturing 2024 | 33,000,000 | |||||
Variable rate demand bonds maturing 2028 | 16,000,000 | |||||
Variable rate demand bonds maturing 2029 | $ 30,000,000 | |||||
Variable rate demand bonds weighted average interest rate | 0.13% | 0.19% | ||||
Amended description of Change in Control | The Consent amends the definition of "Change in Control" in the credit agreement to mean, following consummation of the Merger, an event or series of events by which Exelon no longer owns, directly or indirectly, 100% of the outstanding shares of voting stock of Pepco Holdings. | |||||
Ownership percentage of outstanding voting stock for Change in Control | 100.00% | |||||
Purchase price | $ 5,000,000 | $ 12,000,000 | ||||
Contract payment period | 15 years | 9 years | ||||
Pepco Energy Services [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Maturities of long term debt, 2016 | $ 1,000,000 | |||||
Maturities of long term debt, 2017 | 1,000,000 | |||||
Maturities of long term debt, 2018 | 0 | |||||
Maturities of long term debt, 2019 | 1,000,000 | |||||
Maturities of long term debt, 2020 | 1,000,000 | |||||
Maturities of long term debt, thereafter | 1,000,000 | |||||
Total long-term project funding (including current maturities) | 5,000,000 | $ 10,000,000 | ||||
Purchase price | $ 7,000,000 | |||||
Contract payment period | 23 years | |||||
Senior Medium Term Notes One [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, face amount | 885,000,000 | |||||
Medium-Term Notes [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, carrying value | 40,000,000 | 40,000,000 | ||||
First Mortgage Bonds [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, carrying value | 4,424,000,000 | 3,889,000,000 | ||||
Transition Bonds [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, carrying value | 171,000,000 | 215,000,000 | ||||
Unsecured Notes [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, carrying value | 456,000,000 | 806,000,000 | ||||
Commercial Paper [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Short-term debt | $ 658,000,000 | 624,000,000 | ||||
Unsecured Syndicated Credit Facility [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Credit facility, termination date | Aug. 1, 2018 | |||||
Line of credit facility maximum borrowing capacity | $ 1,500,000,000 | |||||
Parent company credit facility letter of credit, maximum | $ 500,000,000 | |||||
Same day borrowings maximum percentage amount | 10.00% | |||||
Swingline loan repayment period | 14 days | |||||
Credit facility borrowing capacity | $ 750,000,000 | |||||
Maximum amount of credit available to parent | 1,250,000,000 | |||||
Subsidiary borrowing limit under parent's credit facility | $ 500,000,000 | |||||
Maximum number of sublimit reallocations per year | Sublimit | 8 | |||||
Borrowing capacity under the credit facility | $ 851,000,000 | 875,000,000 | ||||
Utility subsidiaries combined cash and borrowing capacity | $ 576,000,000 | 413,000,000 | ||||
Unsecured Syndicated Credit Facility [Member] | Maximum [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Ratio of indebtedness to total capitalization | 65.00% | |||||
Ratio of deferrable interest subordinated debt to total capitalization | 15.00% | |||||
Unsecured Syndicated Credit Facility [Member] | Federal Funds Effective Rate [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, percentage added to reference rate | 0.50% | |||||
Unsecured Syndicated Credit Facility [Member] | One Month London Interbank Offered Rate [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, percentage added to reference rate | 1.00% | |||||
Term Loan [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Short-term debt | $ 300,000,000 | |||||
4.15% Due 2043 [Member] | First Mortgage Bonds [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, face amount | $ 200,000,000 | |||||
Debt instruments maturity date | Mar. 15, 2043 | |||||
Debt instrument, interest percentage | 4.15% | |||||
Debt instrument, yield percentage | 3.90% | |||||
Debt instrument, premium | $ 8,000,000 | |||||
Debt instrument, carrying value | $ 450,000,000 | 250,000,000 | ||||
2.70% Due 2015 [Member] | Unsecured Notes [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, interest percentage | 2.70% | |||||
Debt instrument, carrying value | 250,000,000 | |||||
Repayment of first mortgage bonds | $ 250,000,000 | |||||
Delmarva Power & Light Co/De [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, carrying value | 1,168,000,000 | 1,068,000,000 | ||||
Repayment of first mortgage bonds | 100,000,000 | |||||
Maturities of long term debt, 2016 | 100,000,000 | |||||
Maturities of long term debt, 2017 | 14,000,000 | |||||
Maturities of long term debt, 2018 | 4,000,000 | |||||
Maturities of long term debt, 2019 | 12,000,000 | |||||
Maturities of long term debt, 2020 | 0 | |||||
Maturities of long term debt, thereafter | 1,038,000,000 | |||||
On-going commercial paper | 500,000,000 | |||||
Short-term debt | 210,000,000 | $ 211,000,000 | ||||
Variable rate demand bonds amount | 105,000,000 | |||||
Variable rate demand bonds maturing 2024 | 33,000,000 | |||||
Variable rate demand bonds maturing 2028 | 16,000,000 | |||||
Variable rate demand bonds maturing 2029 | $ 30,000,000 | |||||
Variable rate demand bonds weighted average interest rate | 0.13% | 0.19% | ||||
Amended description of Change in Control | The Consent amends the definition of "Change in Control" in the credit agreement to mean, following consummation of the Merger, an event or series of events by which Exelon no longer owns, directly or indirectly, 100% of the outstanding shares of voting stock of Pepco Holdings. | |||||
Ownership percentage of outstanding voting stock for Change in Control | 100.00% | |||||
Variable rate demand bonds maturing 2017 | $ 26,000,000 | |||||
Delmarva Power & Light Co/De [Member] | Medium-Term Notes [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, face amount | 100,000,000 | |||||
Debt instrument, carrying value | 40,000,000 | $ 40,000,000 | ||||
Delmarva Power & Light Co/De [Member] | First Mortgage Bonds [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, carrying value | 1,050,000,000 | 850,000,000 | ||||
Variable rate demand bonds amount | 72,000,000 | |||||
Delmarva Power & Light Co/De [Member] | Unsecured Notes [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, carrying value | 100,000,000 | |||||
Delmarva Power & Light Co/De [Member] | Commercial Paper [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Short-term debt | $ 105,000,000 | $ 106,000,000 | ||||
Commercial paper weighted average interest rate | 0.47% | 0.26% | ||||
Weighted average maturity, in days | 4 days | 5 days | ||||
Delmarva Power & Light Co/De [Member] | Unsecured Syndicated Credit Facility [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Credit facility, termination date | Aug. 1, 2018 | |||||
Line of credit facility maximum borrowing capacity | $ 1,500,000,000 | |||||
Parent company credit facility letter of credit, maximum | $ 500,000,000 | |||||
Same day borrowings maximum percentage amount | 10.00% | |||||
Swingline loan repayment period | 14 days | |||||
Credit facility borrowing capacity | $ 250,000,000 | |||||
Maximum amount of credit available to parent | 1,250,000,000 | |||||
Subsidiary borrowing limit under parent's credit facility | $ 500,000,000 | |||||
Maximum number of sublimit reallocations per year | Sublimit | 8 | |||||
Utility subsidiaries combined cash and borrowing capacity | $ 576,000,000 | $ 413,000,000 | ||||
Delmarva Power & Light Co/De [Member] | Unsecured Syndicated Credit Facility [Member] | Maximum [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Ratio of indebtedness to total capitalization | 65.00% | |||||
Ratio of deferrable interest subordinated debt to total capitalization | 15.00% | |||||
Delmarva Power & Light Co/De [Member] | Unsecured Syndicated Credit Facility [Member] | Federal Funds Effective Rate [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, percentage added to reference rate | 0.50% | |||||
Delmarva Power & Light Co/De [Member] | Unsecured Syndicated Credit Facility [Member] | One Month London Interbank Offered Rate [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, percentage added to reference rate | 1.00% | |||||
Delmarva Power & Light Co/De [Member] | 4.15% Due 2045 [Member] | First Mortgage Bonds [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, face amount | $ 200,000,000 | |||||
Debt instruments maturity date | May 15, 2045 | |||||
Debt instrument, interest percentage | 4.15% | |||||
Debt instrument, carrying value | $ 200,000,000 | |||||
Delmarva Power & Light Co/De [Member] | 5.00% Due 2015 [Member] | Unsecured Notes [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instruments maturity date | Jun. 1, 2015 | |||||
Debt instrument, interest percentage | 5.00% | |||||
Debt instrument, carrying value | $ 0 | 100,000,000 | ||||
Atlantic City Electric Co [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, carrying value | 1,039,000,000 | 904,000,000 | ||||
Maturities of long term debt, 2016 | 2,000,000 | |||||
Maturities of long term debt, 2017 | 0 | |||||
Maturities of long term debt, 2018 | 250,000,000 | |||||
Maturities of long term debt, 2019 | 0 | |||||
Maturities of long term debt, 2020 | 0 | |||||
Maturities of long term debt, thereafter | 787,000,000 | |||||
On-going commercial paper | 350,000,000 | |||||
Short-term debt | $ 5,000,000 | 127,000,000 | ||||
Variable rate demand bonds amount | $ 18,000,000 | |||||
Variable rate demand bonds weighted average interest rate | 0.05% | |||||
Amended description of Change in Control | The Consent amends the definition of "Change in Control" in the credit agreement to mean, following consummation of the Merger, an event or series of events by which Exelon no longer owns, directly or indirectly, 100% of the outstanding shares of voting stock of Pepco Holdings. | |||||
Ownership percentage of outstanding voting stock for Change in Control | 100.00% | |||||
Atlantic City Electric Co [Member] | Senior Medium Term Notes One [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, face amount | $ 227,000,000 | |||||
Atlantic City Electric Co [Member] | First Mortgage Bonds [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, carrying value | 1,039,000,000 | $ 904,000,000 | ||||
Atlantic City Electric Co [Member] | Tax-Exempt Bonds [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, face amount | 62,000,000 | |||||
Atlantic City Electric Co [Member] | Transition Bonds [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, carrying value | 171,000,000 | 215,000,000 | ||||
Maturities of long term debt, 2016 | 46,000,000 | |||||
Maturities of long term debt, 2017 | 35,000,000 | |||||
Maturities of long term debt, 2018 | 31,000,000 | |||||
Maturities of long term debt, 2019 | 18,000,000 | |||||
Maturities of long term debt, 2020 | 20,000,000 | |||||
Maturities of long term debt, thereafter | 21,000,000 | |||||
Atlantic City Electric Co [Member] | Commercial Paper [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Short-term debt | $ 5,000,000 | $ 127,000,000 | ||||
Commercial paper weighted average interest rate | 0.46% | 0.27% | ||||
Weighted average maturity, in days | 6 days | 5 days | ||||
Atlantic City Electric Co [Member] | Unsecured Syndicated Credit Facility [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Credit facility, termination date | Aug. 1, 2018 | |||||
Line of credit facility maximum borrowing capacity | $ 1,500,000,000 | |||||
Parent company credit facility letter of credit, maximum | $ 500,000,000 | |||||
Same day borrowings maximum percentage amount | 10.00% | |||||
Swingline loan repayment period | 14 days | |||||
Credit facility borrowing capacity | $ 250,000,000 | |||||
Maximum amount of credit available to parent | 1,250,000,000 | |||||
Subsidiary borrowing limit under parent's credit facility | $ 500,000,000 | |||||
Maximum number of sublimit reallocations per year | Sublimit | 8 | |||||
Utility subsidiaries combined cash and borrowing capacity | $ 576,000,000 | $ 413,000,000 | ||||
Atlantic City Electric Co [Member] | Unsecured Syndicated Credit Facility [Member] | Maximum [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Ratio of indebtedness to total capitalization | 65.00% | |||||
Ratio of deferrable interest subordinated debt to total capitalization | 15.00% | |||||
Atlantic City Electric Co [Member] | Unsecured Syndicated Credit Facility [Member] | Federal Funds Effective Rate [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, percentage added to reference rate | 0.50% | |||||
Atlantic City Electric Co [Member] | Unsecured Syndicated Credit Facility [Member] | One Month London Interbank Offered Rate [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, percentage added to reference rate | 1.00% | |||||
Atlantic City Electric Co [Member] | Term Loan [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, face amount | $ 100,000,000 | |||||
Debt instrument, percentage added to reference rate | 0.75% | |||||
Atlantic City Electric Co [Member] | 3.50% Due 2025 [Member] | First Mortgage Bonds [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, face amount | $ 150,000,000 | |||||
Debt instruments maturity date | Dec. 1, 2025 | |||||
Debt instrument, interest percentage | 3.50% | |||||
Debt instrument, carrying value | $ 150,000,000 | |||||
Atlantic City Electric Co [Member] | 7.68% Due 2015 [Member] | First Mortgage Bonds [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instruments maturity date | Aug. 24, 2015 | |||||
Debt instrument, interest percentage | 7.68% | |||||
Repayment of medium term notes | $ 15,000,000 | |||||
Atlantic City Electric Co [Member] | Medium Term Notes Series C [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instruments maturity date | Aug. 24, 2015 | |||||
Debt instrument, interest percentage | 7.68% | |||||
Repayment of secured medium-term notes | $ 15,000,000 | |||||
Potomac Electric Power Co [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, carrying value | 2,335,000,000 | 2,135,000,000 | ||||
Maturities of long term debt, 2016 | 0 | |||||
Maturities of long term debt, 2017 | 0 | |||||
Maturities of long term debt, 2018 | 0 | |||||
Maturities of long term debt, 2019 | 0 | |||||
Maturities of long term debt, 2020 | 0 | |||||
Maturities of long term debt, thereafter | 2,335,000,000 | |||||
On-going commercial paper | 500,000,000 | |||||
Short-term debt | $ 64,000,000 | 104,000,000 | ||||
Amended description of Change in Control | The Consent amends the definition of "Change in Control" in the credit agreement to mean, following consummation of the Merger, an event or series of events by which Exelon no longer owns, directly or indirectly, 100% of the outstanding shares of voting stock of Pepco Holdings. | |||||
Ownership percentage of outstanding voting stock for Change in Control | 100.00% | |||||
Purchase price | $ 5,000,000 | $ 12,000,000 | ||||
Contract payment period | 15 years | 9 years | ||||
Potomac Electric Power Co [Member] | Senior Notes [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, face amount | $ 885,000,000 | |||||
Potomac Electric Power Co [Member] | Tax-Exempt Bonds [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, face amount | 110,000,000 | |||||
Potomac Electric Power Co [Member] | Commercial Paper [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Short-term debt | $ 64,000,000 | $ 104,000,000 | ||||
Commercial paper weighted average interest rate | 0.44% | 0.28% | ||||
Weighted average maturity, in days | 4 days | 6 days | ||||
Potomac Electric Power Co [Member] | Unsecured Syndicated Credit Facility [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Credit facility, termination date | Aug. 1, 2018 | |||||
Line of credit facility maximum borrowing capacity | $ 1,500,000,000 | |||||
Parent company credit facility letter of credit, maximum | $ 500,000,000 | |||||
Same day borrowings maximum percentage amount | 10.00% | |||||
Swingline loan repayment period | 14 days | |||||
Credit facility borrowing capacity | $ 250,000,000 | |||||
Maximum amount of credit available to parent | 1,250,000,000 | |||||
Subsidiary borrowing limit under parent's credit facility | $ 500,000,000 | |||||
Maximum number of sublimit reallocations per year | Sublimit | 8 | |||||
Utility subsidiaries combined cash and borrowing capacity | $ 576,000,000 | $ 413,000,000 | ||||
Potomac Electric Power Co [Member] | Unsecured Syndicated Credit Facility [Member] | Maximum [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Ratio of indebtedness to total capitalization | 65.00% | |||||
Ratio of deferrable interest subordinated debt to total capitalization | 15.00% | |||||
Potomac Electric Power Co [Member] | Unsecured Syndicated Credit Facility [Member] | Federal Funds Effective Rate [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, percentage added to reference rate | 0.50% | |||||
Potomac Electric Power Co [Member] | Unsecured Syndicated Credit Facility [Member] | One Month London Interbank Offered Rate [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, percentage added to reference rate | 1.00% | |||||
Potomac Electric Power Co [Member] | 4.15% Due 2043 [Member] | First Mortgage Bonds [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, face amount | $ 200,000,000 | |||||
Debt instruments maturity date | Mar. 15, 2043 | |||||
Debt instrument, interest percentage | 4.15% | |||||
Debt instrument, yield percentage | 3.90% | |||||
Debt instrument, premium | $ 8,000,000 | |||||
Debt instrument, carrying value | 450,000,000 | 250,000,000 | ||||
PHI [Member] | Commercial Paper [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Short-term debt | $ 484,000,000 | $ 287,000,000 | ||||
Commercial paper weighted average interest rate | 0.80% | 0.57% | ||||
Weighted average maturity, in days | 10 days | 6 days | ||||
PHI [Member] | Term Loan [Member] | Term Loan One [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instruments maturity date | Jul. 28, 2016 | |||||
Debt instrument, carrying value | $ 300,000,000 | |||||
Debt instrument, percentage added to reference rate | 0.95% | |||||
PHI [Member] | Term Loan [Member] | $500 Million Term Loan [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instruments maturity date | Jul. 13, 2016 | |||||
PHI [Member] | Term Loan [Member] | Subsequent Event [Member] | $500 Million Term Loan [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, carrying value | $ 500,000,000 | |||||
Debt instrument, percentage added to reference rate | 0.90% |
Debt - Components of Short-Term
Debt - Components of Short-Term Debt (Detail) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Short-term Debt [Line Items] | ||
Short-term debt | $ 1,063 | $ 729 |
Delmarva Power & Light Co/De [Member] | ||
Short-term Debt [Line Items] | ||
Short-term debt | 210 | 211 |
Atlantic City Electric Co [Member] | ||
Short-term Debt [Line Items] | ||
Short-term debt | 5 | 127 |
Potomac Electric Power Co [Member] | ||
Short-term Debt [Line Items] | ||
Short-term debt | 64 | 104 |
Term Loan [Member] | ||
Short-term Debt [Line Items] | ||
Short-term debt | 300 | |
Commercial Paper [Member] | ||
Short-term Debt [Line Items] | ||
Short-term debt | 658 | 624 |
Commercial Paper [Member] | Delmarva Power & Light Co/De [Member] | ||
Short-term Debt [Line Items] | ||
Short-term debt | 105 | 106 |
Commercial Paper [Member] | Atlantic City Electric Co [Member] | ||
Short-term Debt [Line Items] | ||
Short-term debt | 5 | 127 |
Commercial Paper [Member] | Potomac Electric Power Co [Member] | ||
Short-term Debt [Line Items] | ||
Short-term debt | 64 | 104 |
Variable Rate Demand Bonds [Member] | ||
Short-term Debt [Line Items] | ||
Short-term debt | 105 | 105 |
Variable Rate Demand Bonds [Member] | Delmarva Power & Light Co/De [Member] | ||
Short-term Debt [Line Items] | ||
Short-term debt | $ 105 | $ 105 |
Income Taxes - Provision for Co
Income Taxes - Provision for Consolidated Income Taxes from Continuing Operations (Detail) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Current Tax (Benefit) Expense | |||||||||||
Federal | $ (3) | $ (137) | $ (128) | ||||||||
State and local | 12 | (26) | (9) | ||||||||
Total Current Tax Expense (Benefit) | 9 | (163) | (137) | ||||||||
Deferred Tax Expense (Benefit) | |||||||||||
Federal | 92 | 261 | 393 | ||||||||
State and local | 30 | 41 | 65 | ||||||||
Investment tax credit amortization | (2) | (1) | (2) | ||||||||
Total Deferred Tax Expense | 120 | 301 | 456 | ||||||||
Consolidated Income Tax Expense Related to Continuing Operations | $ 23 | $ 49 | $ 27 | $ 30 | $ 13 | $ 34 | $ 45 | $ 46 | 129 | 138 | 319 |
Potomac Electric Power Co [Member] | |||||||||||
Current Tax (Benefit) Expense | |||||||||||
Federal | (57) | (79) | (39) | ||||||||
State and local | 6 | (3) | (1) | ||||||||
Total Current Tax Expense (Benefit) | (51) | (82) | (40) | ||||||||
Deferred Tax Expense (Benefit) | |||||||||||
Federal | 125 | 150 | 96 | ||||||||
State and local | 24 | 24 | 24 | ||||||||
Investment tax credit amortization | (1) | ||||||||||
Total Deferred Tax Expense | 149 | 174 | 119 | ||||||||
Consolidated Income Tax Expense Related to Continuing Operations | 36 | 32 | 18 | 12 | 10 | 38 | 28 | 16 | 98 | 92 | 79 |
Delmarva Power & Light Co/De [Member] | |||||||||||
Current Tax (Benefit) Expense | |||||||||||
Federal | (26) | (45) | (8) | ||||||||
State and local | 2 | ||||||||||
Total Current Tax Expense (Benefit) | (24) | (45) | (8) | ||||||||
Deferred Tax Expense (Benefit) | |||||||||||
Federal | 73 | 99 | 53 | ||||||||
State and local | 1 | 12 | 12 | ||||||||
Investment tax credit amortization | (1) | (1) | (1) | ||||||||
Total Deferred Tax Expense | 73 | 110 | 64 | ||||||||
Consolidated Income Tax Expense Related to Continuing Operations | 14 | 9 | 5 | 21 | 14 | 13 | 13 | 25 | 49 | 65 | 56 |
Atlantic City Electric Co [Member] | |||||||||||
Current Tax (Benefit) Expense | |||||||||||
Federal | (2) | (7) | (23) | ||||||||
State and local | 3 | (2) | (10) | ||||||||
Total Current Tax Expense (Benefit) | 1 | (9) | (33) | ||||||||
Deferred Tax Expense (Benefit) | |||||||||||
Federal | 25 | 30 | 28 | ||||||||
State and local | 5 | 7 | 25 | ||||||||
Investment tax credit amortization | (1) | ||||||||||
Total Deferred Tax Expense | 30 | 37 | 52 | ||||||||
Consolidated Income Tax Expense Related to Continuing Operations | $ 15 | $ 7 | $ 7 | $ 2 | $ 4 | $ 14 | $ 4 | $ 6 | $ 31 | $ 28 | $ 19 |
Income Taxes - Reconciliation o
Income Taxes - Reconciliation of Consolidated Income Tax Expense from Continuing Operations (Detail) - USD ($) | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Income Tax Rate Reconciliation [Line Items] | |||||||||||
Income tax at Federal statutory rate | $ 156,000,000 | $ 133,000,000 | $ 150,000,000 | ||||||||
State income taxes, net of federal effect | 27,000,000 | 23,000,000 | 27,000,000 | ||||||||
Asset removal costs | (14,000,000) | (12,000,000) | (14,000,000) | ||||||||
Change in estimates and interest related to uncertain and effectively settled tax positions | (46,000,000) | 56,000,000 | |||||||||
Deferred tax basis adjustments | 7,000,000 | ||||||||||
Establishment of valuation allowances related to deferred tax assets | 101,000,000 | ||||||||||
Merger related costs | 4,000,000 | 7,000,000 | |||||||||
Other, net | (5,000,000) | (13,000,000) | (1,000,000) | ||||||||
Consolidated Income Tax Expense Related to Continuing Operations | $ 23,000,000 | $ 49,000,000 | $ 27,000,000 | $ 30,000,000 | $ 13,000,000 | $ 34,000,000 | $ 45,000,000 | $ 46,000,000 | $ 129,000,000 | $ 138,000,000 | $ 319,000,000 |
Income tax at Federal statutory rate, percentage | 35.00% | 35.00% | 35.00% | ||||||||
State income taxes, net of federal effect, percentage | 6.00% | 6.10% | 6.30% | ||||||||
Asset removal costs, percentage | (3.10%) | (3.20%) | (3.30%) | ||||||||
Change in estimates and interest related to uncertain and effectively settled tax positions, percentage | (10.30%) | 13.10% | |||||||||
Deferred tax basis adjustments, percentage | 1.60% | ||||||||||
Establishment of valuation allowances related to deferred tax assets, percentage | 23.50% | ||||||||||
Merger related costs, percentage | 0.90% | 1.80% | |||||||||
Other, net, percentage | (1.20%) | (3.40%) | (0.20%) | ||||||||
Consolidated income tax expense related to continuing operations, percentage | 28.90% | 36.30% | 74.40% | ||||||||
Potomac Electric Power Co [Member] | |||||||||||
Income Tax Rate Reconciliation [Line Items] | |||||||||||
Income tax at Federal statutory rate | $ 100,000,000 | $ 92,000,000 | $ 80,000,000 | ||||||||
State income taxes, net of federal effect | 15,000,000 | 15,000,000 | 13,000,000 | ||||||||
Asset removal costs | (14,000,000) | (12,000,000) | (14,000,000) | ||||||||
Change in estimates and interest related to uncertain and effectively settled tax positions | (6,000,000) | (1,000,000) | (3,000,000) | ||||||||
Deferred tax basis adjustments | 6,000,000 | ||||||||||
Establishment of valuation allowances related to deferred tax assets | 0 | 0 | |||||||||
Other, net | (3,000,000) | (2,000,000) | 3,000,000 | ||||||||
Consolidated Income Tax Expense Related to Continuing Operations | 36,000,000 | 32,000,000 | 18,000,000 | 12,000,000 | 10,000,000 | 38,000,000 | 28,000,000 | 16,000,000 | $ 98,000,000 | $ 92,000,000 | $ 79,000,000 |
Income tax at Federal statutory rate, percentage | 35.00% | 35.00% | 35.00% | ||||||||
State income taxes, net of federal effect, percentage | 5.30% | 5.70% | 5.70% | ||||||||
Asset removal costs, percentage | (4.90%) | (4.60%) | (6.10%) | ||||||||
Change in estimates and interest related to uncertain and effectively settled tax positions, percentage | (2.10%) | (0.40%) | (1.30%) | ||||||||
Deferred tax basis adjustments, percentage | 2.10% | ||||||||||
Other, net, percentage | (1.00%) | (0.70%) | 1.20% | ||||||||
Consolidated income tax expense related to continuing operations, percentage | 34.40% | 35.00% | 34.50% | ||||||||
Delmarva Power & Light Co/De [Member] | |||||||||||
Income Tax Rate Reconciliation [Line Items] | |||||||||||
Income tax at Federal statutory rate | $ 44,000,000 | $ 59,000,000 | $ 51,000,000 | ||||||||
State income taxes, net of federal effect | 7,000,000 | 9,000,000 | 8,000,000 | ||||||||
Change in estimates and interest related to uncertain and effectively settled tax positions | 3,000,000 | (1,000,000) | |||||||||
Establishment of valuation allowances related to deferred tax assets | 0 | 0 | |||||||||
Other, net | (5,000,000) | (3,000,000) | (2,000,000) | ||||||||
Consolidated Income Tax Expense Related to Continuing Operations | 14,000,000 | 9,000,000 | 5,000,000 | 21,000,000 | 14,000,000 | 13,000,000 | 13,000,000 | 25,000,000 | $ 49,000,000 | $ 65,000,000 | $ 56,000,000 |
Income tax at Federal statutory rate, percentage | 35.00% | 35.00% | 35.00% | ||||||||
State income taxes, net of federal effect, percentage | 5.60% | 5.30% | 5.50% | ||||||||
Change in estimates and interest related to uncertain and effectively settled tax positions, percentage | 2.40% | (0.70%) | |||||||||
Other, net, percentage | (3.80%) | (1.80%) | (1.20%) | ||||||||
Consolidated income tax expense related to continuing operations, percentage | 39.20% | 38.50% | 38.60% | ||||||||
Atlantic City Electric Co [Member] | |||||||||||
Income Tax Rate Reconciliation [Line Items] | |||||||||||
Income tax at Federal statutory rate | $ 24,000,000 | $ 26,000,000 | $ 24,000,000 | ||||||||
State income taxes, net of federal effect | 4,000,000 | 4,000,000 | 5,000,000 | ||||||||
Change in estimates and interest related to uncertain and effectively settled tax positions | 3,000,000 | (1,000,000) | (9,000,000) | ||||||||
Deferred tax basis adjustments | 2,000,000 | (2,000,000) | |||||||||
Establishment of valuation allowances related to deferred tax assets | 0 | 0 | |||||||||
Investment tax credit amortization | (1,000,000) | ||||||||||
Other, net | (2,000,000) | (1,000,000) | 2,000,000 | ||||||||
Consolidated Income Tax Expense Related to Continuing Operations | $ 15,000,000 | $ 7,000,000 | $ 7,000,000 | $ 2,000,000 | $ 4,000,000 | $ 14,000,000 | $ 4,000,000 | $ 6,000,000 | $ 31,000,000 | $ 28,000,000 | $ 19,000,000 |
Income tax at Federal statutory rate, percentage | 35.00% | 35.00% | 35.00% | ||||||||
State income taxes, net of federal effect, percentage | 5.80% | 5.50% | 7.20% | ||||||||
Change in estimates and interest related to uncertain and effectively settled tax positions, percentage | 4.30% | (1.40%) | (13.00%) | ||||||||
Deferred tax basis adjustments, percentage | 2.90% | (2.90%) | |||||||||
Investment tax credit amortization, percentage | (1.40%) | ||||||||||
Other, net, percentage | (3.10%) | (0.70%) | 2.60% | ||||||||
Consolidated income tax expense related to continuing operations, percentage | 44.90% | 38.40% | 27.50% |
Income Taxes - Additional Infor
Income Taxes - Additional Information (Detail) - USD ($) | Feb. 26, 2015 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Schedule of Income Tax [Line Items] | |||||||||||||
Tax expense (benefit) | $ 23,000,000 | $ 49,000,000 | $ 27,000,000 | $ 30,000,000 | $ 13,000,000 | $ 34,000,000 | $ 45,000,000 | $ 46,000,000 | $ 129,000,000 | $ 138,000,000 | $ 319,000,000 | ||
Change in estimates and interest related to uncertain tax positions | 56,000,000 | ||||||||||||
Establishment of valuation allowances on deferred tax assets | 63,000,000 | 61,000,000 | $ 63,000,000 | 61,000,000 | 101,000,000 | ||||||||
PCI future deferred tax asset | 101,000,000 | ||||||||||||
Federal and state net operating losses, years | 20 years | ||||||||||||
Federal and state net operating losses, expiration start period | 2,029 | ||||||||||||
Federal and state net operating losses, expiration end period | 2,034 | ||||||||||||
Unrecognized tax benefits that would impact effective tax rate | 22,000,000 | $ 22,000,000 | |||||||||||
Uncertain tax position pre-tax interest income (expense) recognized | 35,000,000 | 1,000,000 | (125,000,000) | ||||||||||
Uncertain tax position after-tax interest income (expense) recognized | 21,000,000 | (75,000,000) | |||||||||||
Accrued interest payable | 49,000,000 | 47,000,000 | 49,000,000 | 47,000,000 | |||||||||
Reduction in deferred tax liabilities | 2,000,000 | 23,000,000 | |||||||||||
Other taxes for continuing operations | 421,000,000 | 407,000,000 | 422,000,000 | ||||||||||
Uncertain tax positions settled in Global Tax Settlement | 628,000,000 | 6,000,000 | |||||||||||
After-tax effect of revised lease rerun | $ 377,000,000 | ||||||||||||
Valuation allowance for deferred tax assets | 101,000,000 | ||||||||||||
Change in estimates and interest related to uncertain and effectively settled tax positions | (46,000,000) | 56,000,000 | |||||||||||
District of Columbia [Member] | |||||||||||||
Schedule of Income Tax [Line Items] | |||||||||||||
Corporate tax rate | 9.975% | ||||||||||||
District of Columbia [Member] | 2019 [Member] | |||||||||||||
Schedule of Income Tax [Line Items] | |||||||||||||
Corporate tax rate | 8.25% | ||||||||||||
District of Columbia [Member] | 2015 [Member] | |||||||||||||
Schedule of Income Tax [Line Items] | |||||||||||||
Corporate tax rate | 9.40% | ||||||||||||
District of Columbia [Member] | 2016 [Member] | |||||||||||||
Schedule of Income Tax [Line Items] | |||||||||||||
Corporate tax rate | 9.20% | ||||||||||||
Potomac Electric Power Co [Member] | |||||||||||||
Schedule of Income Tax [Line Items] | |||||||||||||
Tax expense (benefit) | 36,000,000 | 32,000,000 | 18,000,000 | 12,000,000 | 10,000,000 | 38,000,000 | 28,000,000 | 16,000,000 | $ 98,000,000 | 92,000,000 | 79,000,000 | ||
Federal and state net operating losses, years | 20 years | ||||||||||||
Federal and state net operating losses, expiration start period | 2,029 | ||||||||||||
Federal and state net operating losses, expiration end period | 2,034 | ||||||||||||
Unrecognized tax benefits that would impact effective tax rate | 8,000,000 | $ 8,000,000 | |||||||||||
Uncertain tax position pre-tax interest income (expense) recognized | 5,000,000 | 2,000,000 | 5,000,000 | ||||||||||
Uncertain tax position after-tax interest income (expense) recognized | 3,000,000 | 1,000,000 | 3,000,000 | ||||||||||
Accrued interest receivable | 0 | 9,000,000 | 0 | 9,000,000 | 9,000,000 | ||||||||
Accrued interest payable | 22,000,000 | 19,000,000 | 22,000,000 | 19,000,000 | |||||||||
Reduction in deferred tax liabilities | 2,000,000 | 23,000,000 | |||||||||||
Uncertain tax positions settled in Global Tax Settlement | 40,000,000 | ||||||||||||
Interest expense on uncertain tax positions | 3,000,000 | ||||||||||||
After-tax effect of revised lease rerun | 377,000,000 | ||||||||||||
After-tax non-cash charge | 54,000,000 | ||||||||||||
Additional interest income | 5,000,000 | ||||||||||||
Valuation allowance for deferred tax assets | 0 | 0 | |||||||||||
Change in estimates and interest related to uncertain and effectively settled tax positions | (6,000,000) | (1,000,000) | (3,000,000) | ||||||||||
Potomac Electric Power Co [Member] | District of Columbia [Member] | |||||||||||||
Schedule of Income Tax [Line Items] | |||||||||||||
Corporate tax rate | 9.975% | ||||||||||||
Potomac Electric Power Co [Member] | District of Columbia [Member] | 2019 [Member] | |||||||||||||
Schedule of Income Tax [Line Items] | |||||||||||||
Corporate tax rate | 8.25% | ||||||||||||
Potomac Electric Power Co [Member] | District of Columbia [Member] | 2015 [Member] | |||||||||||||
Schedule of Income Tax [Line Items] | |||||||||||||
Corporate tax rate | 9.40% | ||||||||||||
Potomac Electric Power Co [Member] | District of Columbia [Member] | 2016 [Member] | |||||||||||||
Schedule of Income Tax [Line Items] | |||||||||||||
Corporate tax rate | 9.20% | ||||||||||||
Delmarva Power & Light Co/De [Member] | |||||||||||||
Schedule of Income Tax [Line Items] | |||||||||||||
Tax expense (benefit) | 14,000,000 | 9,000,000 | 5,000,000 | 21,000,000 | 14,000,000 | 13,000,000 | 13,000,000 | 25,000,000 | $ 49,000,000 | 65,000,000 | 56,000,000 | ||
Federal and state net operating losses, years | 20 years | ||||||||||||
Federal and state net operating losses, expiration start period | 2,029 | ||||||||||||
Federal and state net operating losses, expiration end period | 2,034 | ||||||||||||
Unrecognized tax benefits that would impact effective tax rate | 3,000,000 | $ 3,000,000 | |||||||||||
Uncertain tax position pre-tax interest income (expense) recognized | 1,000,000 | 1,000,000 | 1,000,000 | ||||||||||
Accrued interest receivable | 0 | 2,000,000 | 0 | 2,000,000 | 2,000,000 | ||||||||
Accrued interest payable | 7,000,000 | 7,000,000 | 7,000,000 | 7,000,000 | |||||||||
Uncertain tax positions settled in Global Tax Settlement | 9,000,000 | ||||||||||||
After-tax effect of revised lease rerun | 377,000,000 | ||||||||||||
After-tax non-cash charge | 54,000,000 | ||||||||||||
Additional interest income | 1,000,000 | ||||||||||||
Valuation allowance for deferred tax assets | 0 | 0 | |||||||||||
Change in estimates and interest related to uncertain and effectively settled tax positions | 3,000,000 | (1,000,000) | |||||||||||
Atlantic City Electric Co [Member] | |||||||||||||
Schedule of Income Tax [Line Items] | |||||||||||||
Tax expense (benefit) | 15,000,000 | $ 7,000,000 | $ 7,000,000 | $ 2,000,000 | 4,000,000 | $ 14,000,000 | $ 4,000,000 | $ 6,000,000 | $ 31,000,000 | 28,000,000 | 19,000,000 | ||
Federal and state net operating losses, years | 20 years | ||||||||||||
Federal and state net operating losses, expiration start period | 2,029 | ||||||||||||
Federal and state net operating losses, expiration end period | 2,032 | ||||||||||||
Unrecognized tax benefits that would impact effective tax rate | 0 | $ 0 | |||||||||||
Uncertain tax position pre-tax interest income (expense) recognized | 1,000,000 | 1,000,000 | 12,000,000 | ||||||||||
Uncertain tax position after-tax interest income (expense) recognized | 1,000,000 | 1,000,000 | 7,000,000 | ||||||||||
Accrued interest receivable | 0 | 14,000,000 | 0 | 14,000,000 | 14,000,000 | ||||||||
Accrued interest payable | 13,000,000 | 13,000,000 | 13,000,000 | 13,000,000 | |||||||||
Uncertain tax positions settled in Global Tax Settlement | 3,000,000 | 6,000,000 | |||||||||||
After-tax effect of revised lease rerun | 377,000,000 | ||||||||||||
After-tax non-cash charge | 54,000,000 | ||||||||||||
Additional interest income | $ 6,000,000 | ||||||||||||
Valuation allowance for deferred tax assets | 0 | 0 | |||||||||||
Change in estimates and interest related to uncertain and effectively settled tax positions | 3,000,000 | (1,000,000) | (9,000,000) | ||||||||||
Tax Settlement [Member] | |||||||||||||
Schedule of Income Tax [Line Items] | |||||||||||||
Total income tax benefit | (56,000,000) | ||||||||||||
Tax expense (benefit) | (47,000,000) | ||||||||||||
Income tax benefit discontinued operations | (9,000,000) | ||||||||||||
After-tax interest benefit | (21,000,000) | ||||||||||||
Uncertain tax positions settled in Global Tax Settlement | (26,000,000) | ||||||||||||
Deferred tax basis adjustments | 7,000,000 | ||||||||||||
Tax Settlement [Member] | Potomac Electric Power Co [Member] | |||||||||||||
Schedule of Income Tax [Line Items] | |||||||||||||
Tax expense (benefit) | (9,000,000) | ||||||||||||
After-tax interest benefit | (21,000,000) | ||||||||||||
Deferred tax basis adjustments | 6,000,000 | ||||||||||||
Uncertain tax positions, after-tax interest benefit | 3,000,000 | ||||||||||||
Uncertain tax positions settled in Global Tax Settlement | 6,000,000 | ||||||||||||
Tax Settlement [Member] | Delmarva Power & Light Co/De [Member] | |||||||||||||
Schedule of Income Tax [Line Items] | |||||||||||||
Tax expense (benefit) | 3,000,000 | 3,000,000 | |||||||||||
After-tax interest benefit | (21,000,000) | ||||||||||||
Change in estimates and interest related to uncertain and effectively settled tax positions | 3,000,000 | ||||||||||||
Uncertain tax positions, after-tax interest benefit | 1,000,000 | ||||||||||||
Tax Settlement [Member] | Atlantic City Electric Co [Member] | |||||||||||||
Schedule of Income Tax [Line Items] | |||||||||||||
Tax expense (benefit) | 3,000,000 | ||||||||||||
After-tax interest benefit | (21,000,000) | ||||||||||||
Deferred tax basis adjustments | 2,000,000 | ||||||||||||
Change in estimates and interest related to uncertain and effectively settled tax positions | 3,000,000 | ||||||||||||
Uncertain tax positions, after-tax interest expense | 1,000,000 | ||||||||||||
Interest and Penalties [Member] | |||||||||||||
Schedule of Income Tax [Line Items] | |||||||||||||
Accrued interest receivable | $ 2,000,000 | 2,000,000 | $ 2,000,000 | ||||||||||
Accrued interest payable | 2,000,000 | 2,000,000 | |||||||||||
Pepco Energy Services' Energy Savings Performance Contract [Member] | |||||||||||||
Schedule of Income Tax [Line Items] | |||||||||||||
Tax benefit related to certain energy efficiency tax deductions | 6,000,000 | $ 5,000,000 | |||||||||||
Minimum [Member] | |||||||||||||
Schedule of Income Tax [Line Items] | |||||||||||||
Estimated possible decrease in unrecognized tax benefit | 6,000,000 | 6,000,000 | |||||||||||
Minimum [Member] | Potomac Electric Power Co [Member] | |||||||||||||
Schedule of Income Tax [Line Items] | |||||||||||||
Estimated possible decrease in unrecognized tax benefit | 3,000,000 | 3,000,000 | |||||||||||
Minimum [Member] | Delmarva Power & Light Co/De [Member] | |||||||||||||
Schedule of Income Tax [Line Items] | |||||||||||||
Estimated possible decrease in unrecognized tax benefit | 0 | 0 | |||||||||||
Minimum [Member] | Atlantic City Electric Co [Member] | |||||||||||||
Schedule of Income Tax [Line Items] | |||||||||||||
Estimated possible decrease in unrecognized tax benefit | 0 | 0 | |||||||||||
Maximum [Member] | |||||||||||||
Schedule of Income Tax [Line Items] | |||||||||||||
Estimated possible decrease in unrecognized tax benefit | 10,000,000 | 10,000,000 | |||||||||||
Maximum [Member] | Potomac Electric Power Co [Member] | |||||||||||||
Schedule of Income Tax [Line Items] | |||||||||||||
Estimated possible decrease in unrecognized tax benefit | 5,000,000 | 5,000,000 | |||||||||||
Maximum [Member] | Delmarva Power & Light Co/De [Member] | |||||||||||||
Schedule of Income Tax [Line Items] | |||||||||||||
Estimated possible decrease in unrecognized tax benefit | 0 | 0 | |||||||||||
Maximum [Member] | Atlantic City Electric Co [Member] | |||||||||||||
Schedule of Income Tax [Line Items] | |||||||||||||
Estimated possible decrease in unrecognized tax benefit | $ 0 | $ 0 |
Income Taxes - Components of Co
Income Taxes - Components of Consolidated Deferred Tax Liabilities (Assets) (Detail) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Schedule Of Deferred Income Tax Assets And Liabilities [Line Items] | |||
Depreciation and other basis differences related to plant and equipment | $ 3,273 | $ 2,962 | |
Deferred electric service and electric restructuring liabilities | 43 | 67 | |
Federal and state net operating losses | (446) | (400) | |
Valuation allowances on state net operating losses | 63 | 61 | $ 101 |
Pension and other postretirement benefits | 92 | 116 | |
Deferred taxes on amounts to be collected through future rates | 86 | 94 | |
Other | 267 | 325 | |
Total Consolidated Deferred Tax Liabilities, net | 3,378 | 3,225 | |
Deferred tax assets included in Other Assets | 0 | 0 | |
Total Consolidated Deferred Tax Liabilities, net | 3,393 | 3,242 | |
Potomac Electric Power Co [Member] | |||
Schedule Of Deferred Income Tax Assets And Liabilities [Line Items] | |||
Depreciation and other basis differences related to plant and equipment | 1,541 | 1,423 | |
Federal and state net operating losses | (141) | (186) | |
Pension and other postretirement benefits | 95 | 103 | |
Deferred taxes on amounts to be collected through future rates | 55 | 59 | |
Other | 171 | 180 | |
Total Consolidated Deferred Tax Liabilities, net | 1,721 | 1,579 | |
Total Consolidated Deferred Tax Liabilities, net | 1,721 | 1,579 | |
Delmarva Power & Light Co/De [Member] | |||
Schedule Of Deferred Income Tax Assets And Liabilities [Line Items] | |||
Depreciation and other basis differences related to plant and equipment | 899 | 797 | |
Deferred electric service and electric restructuring liabilities | (4) | (4) | |
Federal and state net operating losses | (122) | (115) | |
Pension and other postretirement benefits | 75 | 80 | |
Deferred taxes on amounts to be collected through future rates | 15 | 19 | |
Other | 78 | 101 | |
Total Consolidated Deferred Tax Liabilities, net | 941 | 878 | |
Total Consolidated Deferred Tax Liabilities, net | 941 | 878 | |
Atlantic City Electric Co [Member] | |||
Schedule Of Deferred Income Tax Assets And Liabilities [Line Items] | |||
Depreciation and other basis differences related to plant and equipment | 773 | 691 | |
Deferred electric service and electric restructuring liabilities | 47 | 71 | |
Federal and state net operating losses | (9) | (26) | |
Pension and other postretirement benefits | 20 | 25 | |
Deferred taxes on amounts to be collected through future rates | 17 | 16 | |
Payment for termination of purchased power contracts with NUGs | 34 | 38 | |
Other | 6 | 40 | |
Total Consolidated Deferred Tax Liabilities, net | 888 | 855 | |
Total Consolidated Deferred Tax Liabilities, net | $ 888 | $ 855 |
Income Taxes - Reconciliation86
Income Taxes - Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Unrecognized Tax Benefits [Line Items] | |||
Unrecognized Tax Benefits, Beginning balance | $ 850 | $ 831 | $ 200 |
Tax positions related to current year, Additions | 4 | 3 | |
Tax positions related to current year, Reductions | (2) | ||
Tax positions related to prior years, Additions | 13 | 27 | 646 |
Tax positions related to prior years, Reductions | (201) | (10) | (12) |
Settlements | (628) | (6) | |
Unrecognized Tax Benefits, Ending balance | 34 | 850 | 831 |
Potomac Electric Power Co [Member] | |||
Unrecognized Tax Benefits [Line Items] | |||
Unrecognized Tax Benefits, Beginning balance | 97 | 101 | 91 |
Tax positions related to current year, Additions | 1 | 1 | |
Tax positions related to current year, Reductions | (2) | ||
Tax positions related to prior years, Additions | 10 | 1 | 12 |
Tax positions related to prior years, Reductions | (55) | (4) | (3) |
Settlements | (40) | ||
Unrecognized Tax Benefits, Ending balance | 12 | 97 | 101 |
Delmarva Power & Light Co/De [Member] | |||
Unrecognized Tax Benefits [Line Items] | |||
Unrecognized Tax Benefits, Beginning balance | 22 | 9 | 9 |
Tax positions related to current year, Additions | 1 | ||
Tax positions related to current year, Reductions | 0 | ||
Tax positions related to prior years, Additions | 3 | 13 | |
Tax positions related to prior years, Reductions | (13) | (1) | |
Settlements | (9) | ||
Unrecognized Tax Benefits, Ending balance | 3 | 22 | 9 |
Atlantic City Electric Co [Member] | |||
Unrecognized Tax Benefits [Line Items] | |||
Unrecognized Tax Benefits, Beginning balance | 13 | 9 | 17 |
Tax positions related to current year, Additions | 1 | 2 | |
Tax positions related to prior years, Additions | 5 | 1 | |
Tax positions related to prior years, Reductions | (10) | (2) | (5) |
Settlements | $ (3) | (6) | |
Unrecognized Tax Benefits, Ending balance | $ 13 | $ 9 |
Income Taxes - Other Taxes (Det
Income Taxes - Other Taxes (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Schedule of Income Tax [Line Items] | |||
Gross Receipts/Delivery | $ 124 | $ 123 | $ 133 |
Property | 92 | 84 | 77 |
County Fuel and Energy | 143 | 143 | 153 |
Environmental, Use and Other | 68 | 63 | 65 |
Total | 427 | 413 | 428 |
Potomac Electric Power Co [Member] | |||
Schedule of Income Tax [Line Items] | |||
Gross Receipts/Delivery | 107 | 107 | 108 |
Property | 55 | 51 | 45 |
County Fuel and Energy | 143 | 143 | 153 |
Environmental, Use and Other | 64 | 62 | 62 |
Total | 369 | 363 | 368 |
Delmarva Power & Light Co/De [Member] | |||
Schedule of Income Tax [Line Items] | |||
Gross Receipts/Delivery | 17 | 16 | 15 |
Property | 28 | 24 | 24 |
Environmental, Use and Other | 2 | 2 | 1 |
Total | 47 | 42 | 40 |
Atlantic City Electric Co [Member] | |||
Schedule of Income Tax [Line Items] | |||
Gross Receipts/Delivery | 10 | ||
Property | 4 | 3 | 3 |
Environmental, Use and Other | 1 | (1) | 1 |
Total | $ 5 | $ 2 | $ 14 |
Stock-Based Compensation, Div88
Stock-Based Compensation, Dividend Restrictions, and Calculations of Earnings Per Share of Common Stock - Additional Information (Detail) | Feb. 27, 2013USD ($)$ / EquityUnit | Dec. 31, 2015USD ($)shares | Dec. 31, 2014USD ($)shares | Dec. 31, 2013USD ($)shares | Dec. 31, 2012$ / sharesshares |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Shares of common stock authorized for issuance | shares | 10,000,000 | ||||
Capitalized stock-based compensation expense | $ 0 | $ 0 | $ 0 | ||
Eligible percentage of common stock over the performance period target award minimum | 25.00% | ||||
Eligible percentage of common stock over the performance period target award maximum | 200.00% | ||||
Requisite service period (years) | 3 years | ||||
Vesting Period | 1 year | 1 year | |||
Unrecognized compensation expense | $ 12,000,000 | ||||
Costs recognized, weighted average period (years) | 2 years | ||||
Stock option expiration (years) | 10 years | ||||
Stock options outstanding | shares | 0 | ||||
Recognized compensation expense | $ 0 | $ 1,000,000 | $ 0 | ||
Deferred compensation balance | $ 2,000,000 | 2,000,000 | |||
Ratio of equity to total capitalization | 30.00% | ||||
Retained earnings | $ 617,000,000 | $ 565,000,000 | |||
Restricted net assets for consolidated subsidiaries | 2,633,000,000 | ||||
Shares of PHI common stock | shares | 17,922,077 | ||||
Public offering price | $ / shares | $ 19.25 | ||||
Underwriting discount | $ / shares | 0.67375 | ||||
Initial pricing of equity forward instruments | $ / shares | $ 18.57625 | ||||
Forward sale price | $ / EquityUnit | 17.39 | ||||
Proceeds from equity forward transaction | $ 312,000,000 | ||||
Purchases of common stock minimum per calendar month | 25 | ||||
Purchases of common stock maximum per calendar year | $ 300,000 | ||||
Shares issued and sold under the DRP | shares | 1,000,000 | 1,000,000 | 2,000,000 | ||
2012 LTIP [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Shares of common stock authorized for issuance | shares | 8,000,000 | ||||
Performance Based Restricted Stock Award [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Stock-based compensation expense | $ 13,000,000 | $ 18,000,000 | $ 12,000,000 | ||
Time-Based Restricted Stock Units were Granted to Each Non-Employee Director [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Restricted stock units were granted to each non-employee director | shares | 22,901 | 21,138 | |||
Vesting Period | 3 years |
Stock-Based Compensation, Div89
Stock-Based Compensation, Dividend Restrictions, and Calculations of Earnings Per Share of Common Stock - Schedule of Restricted Stock and Restricted Stock Units (Detail) | 12 Months Ended |
Dec. 31, 2015$ / sharesshares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Number of shares outstanding, beginning balance | 1,421,380 |
Granted, number of shares | 504,738 |
Forfeited, number of shares | (3,044) |
Vested, number of shares | (807,040) |
Number of shares outstanding, ending balance | 1,116,034 |
Restricted Stock [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Number of shares outstanding, beginning balance | 54,165 |
Number of shares outstanding, ending balance | 54,165 |
Weighted average grant date fair value, beginning of period | $ / shares | $ 26.80 |
Weighted average grant date fair value, ending of period | $ / shares | $ 26.80 |
Performance-Based Restricted Stock [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Number of shares outstanding, beginning balance | 70,276 |
Granted, number of shares | 48,347 |
Vested, number of shares | (93,906) |
Number of shares outstanding, ending balance | 24,717 |
Weighted average grant date fair value, beginning of period | $ / shares | $ 27.01 |
Granted, weighted average grant date fair value | $ / shares | 26.10 |
Vested, weighted average grant date fair value | $ / shares | 26.78 |
Weighted average grant date fair value, ending of period | $ / shares | $ 26.10 |
Time-Based Restricted Stock Units Award [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Number of shares outstanding, beginning balance | 468,958 |
Granted, number of shares | 450,203 |
Forfeited, number of shares | (2,218) |
Vested, number of shares | (288,429) |
Number of shares outstanding, ending balance | 628,514 |
Weighted average grant date fair value, beginning of period | $ / shares | $ 19.61 |
Granted, weighted average grant date fair value | $ / shares | 27.40 |
Forfeited, weighted average grant date fair value | $ / shares | 27 |
Vested, weighted average grant date fair value | $ / shares | 20.61 |
Weighted average grant date fair value, ending of period | $ / shares | $ 24.71 |
Performance Based Restricted Stock Units [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Number of shares outstanding, beginning balance | 827,981 |
Granted, number of shares | 6,188 |
Forfeited, number of shares | (826) |
Vested, number of shares | (424,705) |
Number of shares outstanding, ending balance | 408,638 |
Weighted average grant date fair value, beginning of period | $ / shares | $ 17.73 |
Granted, weighted average grant date fair value | $ / shares | 26.08 |
Forfeited, weighted average grant date fair value | $ / shares | 19.33 |
Vested, weighted average grant date fair value | $ / shares | 17.05 |
Weighted average grant date fair value, ending of period | $ / shares | $ 18.56 |
Stock-Based Compensation, Div90
Stock-Based Compensation, Dividend Restrictions, and Calculations of Earnings Per Share of Common Stock - Schedule of Restricted Stock and Restricted Stock Units (Parenthetical) (Detail) | Dec. 31, 2014shares |
Executive Officer [Member] | Restricted Stock [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Number of shares vested but not yet settled | 36,110 |
Executive Officer [Member] | Time-Based Restricted Stock Units Award [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Number of shares vested but not yet settled | 113,385 |
Executive Officer [Member] | Performance Based Restricted Stock Units [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Number of shares vested but not yet settled | 104,628 |
Director [Member] | Time-Based Restricted Stock Units Award [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Number of shares vested but not yet settled | 30,784 |
Stock-Based Compensation, Div91
Stock-Based Compensation, Dividend Restrictions, and Calculations of Earnings Per Share of Common Stock - Weighted Average Grant Date Fair Value Per Share (Detail) - $ / shares | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Restricted Stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Weighted average grant-date fair value per share of award granted during the year | $ 26.80 | ||
Performance-Based Restricted Stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Weighted average grant-date fair value per share of award granted during the year | $ 26.10 | 27.01 | |
Time-Based Restricted Stock Units Award [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Weighted average grant-date fair value per share of award granted during the year | 27.40 | 19.77 | $ 19.70 |
Performance Based Restricted Stock Units [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Weighted average grant-date fair value per share of award granted during the year | $ 26.08 | $ 18.53 | $ 17.03 |
Stock-Based Compensation, Div92
Stock-Based Compensation, Dividend Restrictions, and Calculations of Earnings Per Share of Common Stock - Dividends Received from Subsidiaries (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items] | |||
Dividends received from subsidiaries | $ 250 | $ 212 | $ 136 |
Potomac Electric Power Co [Member] | |||
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items] | |||
Dividends received from subsidiaries | 146 | 86 | 46 |
Delmarva Power & Light Co/De [Member] | |||
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items] | |||
Dividends received from subsidiaries | 92 | 100 | 30 |
Atlantic City Electric Co [Member] | |||
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items] | |||
Dividends received from subsidiaries | $ 12 | $ 26 | $ 60 |
Stock-Based Compensation, Div93
Stock-Based Compensation, Dividend Restrictions, and Calculations of Earnings Per Share of Common Stock - Calculation of Earnings Per Share of Common Stock (Detail) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Earnings Per Share [Abstract] | |||||||||||
Net Income from Continuing Operations | $ 121 | $ 91 | $ 53 | $ 53 | $ 318 | $ 242 | $ 110 | ||||
Net income (loss) from discontinued operations | 9 | 9 | (322) | ||||||||
Net Income (Loss) | $ 130 | $ 91 | $ 53 | $ 53 | $ 35 | $ 79 | $ 53 | $ 75 | $ 327 | $ 242 | $ (212) |
Average shares outstanding | 253 | 251 | 246 | ||||||||
Adjustment to shares outstanding | 0 | 0 | 0 | ||||||||
Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock | 253 | 251 | 246 | ||||||||
Net effect of potentially dilutive shares | 1 | 1 | |||||||||
Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock | 254 | 252 | 246 | ||||||||
Basic earnings per share of common stock from continuing operations | $ 1.25 | $ 0.96 | $ 0.45 | ||||||||
Basic earnings (loss) per share of common stock from discontinued operations | 0.04 | (1.31) | |||||||||
Basic earnings (loss) per share | 1.29 | 0.96 | (0.86) | ||||||||
Diluted earnings per share of common stock from continuing operations | 1.25 | 0.96 | 0.45 | ||||||||
Diluted earnings (loss) per share of common stock from discontinued operations | 0.04 | (1.31) | |||||||||
Diluted earnings (loss) per share | $ 1.29 | $ 0.96 | $ (0.86) |
Stock-Based Compensation, Div94
Stock-Based Compensation, Dividend Restrictions, and Calculations of Earnings Per Share of Common Stock - Calculation of Earnings Per Share of Common Stock (Parenthetical) (Detail) - shares | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Earnings Per Share [Abstract] | |||
Antidilutive securities excluded from computation of earnings per share, amount | 0 | 0 | 0 |
Stock-Based Compensation, Div95
Stock-Based Compensation, Dividend Restrictions, and Calculations of Earnings Per Share of Common Stock - Common Stock Reserved and Unissued (Detail) | Dec. 31, 2015shares |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Number of shares | 22,123,913 |
DRP [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Number of shares | 4,584,077 |
Pepco Holdings Long-Term Incentive Plan [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Number of shares | 6,946,614 |
Pepco Holdings 2012 Long-Term Incentive Plan [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Number of shares | 7,136,961 |
Pepco Holdings Retirement Savings Plan [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Number of shares | 3,456,261 |
Preferred Stock - Additional In
Preferred Stock - Additional Information (Detail) - USD ($) | Jul. 24, 2015 | Apr. 27, 2015 | Jan. 26, 2015 | Oct. 27, 2014 | Jul. 29, 2014 | Apr. 30, 2014 | Sep. 30, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | Apr. 29, 2014 |
Class of Stock [Line Items] | ||||||||||
Amount of Non Voting Series A Preferred Stock Purchase price | $ 54,000,000 | $ 126,000,000 | ||||||||
Redemption of issued and outstanding Preferred Stock, par value | $ 0.01 | $ 0.01 | ||||||||
Increase in fair value of preferred stock derivative | $ 15,000,000 | $ 15,000,000 | ||||||||
Non-Voting Series A Preferred Stock [Member] | ||||||||||
Class of Stock [Line Items] | ||||||||||
Issuance of non-voting Series A Preferred Stock, shares issued | 9,000 | |||||||||
Non-voting Series A Preferred Stock, maximum number of shares issued | 1,800 | 1,800 | 1,800 | 1,800 | 1,800 | |||||
Non-voting Series A Preferred Stock, shares purchased price | $ 90,000,000 | |||||||||
Amount of Non Voting Series A Preferred Stock Purchase price | $ 18,000,000 | $ 18,000,000 | $ 18,000,000 | $ 18,000,000 | $ 18,000,000 | |||||
Non-voting Series A Preferred Stock, maximum aggregate consideration | $ 180,000,000 | |||||||||
Non-voting Series A Preferred Stock, cumulative, non-participating cash dividend | 0.10% | |||||||||
Redemption of preferred stock at purchase price | $ 10,000 | |||||||||
Redemption of issued and outstanding Preferred Stock, par value | $ 0.01 | |||||||||
Non-Voting Series A Preferred Stock [Member] | Maximum [Member] | ||||||||||
Class of Stock [Line Items] | ||||||||||
Non-voting Series A Preferred Stock, maximum number of shares issued | 18,000 | |||||||||
Preferred Stock [Member] | ||||||||||
Class of Stock [Line Items] | ||||||||||
Derivative instruments, assets | $ 18,000,000 | $ 3,000,000 |
Derivative Instruments and He97
Derivative Instruments and Hedging Activities - Fair Values of Derivative Instruments by Balance Sheet Location (Detail) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Gross Derivative Instruments [Member] | ||
Derivative [Line Items] | ||
Derivative assets (current assets) | $ 18 | $ 3 |
Derivative liabilities (current liabilities) | (2) | (4) |
Net derivative (liability) asset | 16 | (1) |
Net Derivative Instruments [Member] | ||
Derivative [Line Items] | ||
Derivative assets (current assets) | 18 | 3 |
Net derivative (liability) asset | 18 | 3 |
Other Derivative Instruments [Member] | ||
Derivative [Line Items] | ||
Derivative assets (current assets) | 18 | 3 |
Derivative liabilities (current liabilities) | (2) | (4) |
Net derivative (liability) asset | 16 | (1) |
Delmarva Power & Light Co/De [Member] | Gross Derivative Instruments [Member] | ||
Derivative [Line Items] | ||
Derivative liabilities (current liabilities) | (2) | (4) |
Delmarva Power & Light Co/De [Member] | Other Derivative Instruments [Member] | ||
Derivative [Line Items] | ||
Derivative liabilities (current liabilities) | (2) | (4) |
Effects of Cash Collateral and Netting [Member] | ||
Derivative [Line Items] | ||
Derivative liabilities (current liabilities) | 2 | 4 |
Net derivative (liability) asset | 2 | 4 |
Effects of Cash Collateral and Netting [Member] | Delmarva Power & Light Co/De [Member] | ||
Derivative [Line Items] | ||
Derivative liabilities (current liabilities) | $ 2 | $ 4 |
Derivative Instruments and He98
Derivative Instruments and Hedging Activities - Schedule of Cash Collateral Offset Against Derivative Positions (Detail) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Derivative [Line Items] | ||
Cash collateral pledged to counterparties with the right to reclaim | $ 2 | $ 4 |
Delmarva Power & Light Co/De [Member] | ||
Derivative [Line Items] | ||
Cash collateral pledged to counterparties with the right to reclaim | $ 2 | $ 4 |
Derivative Instruments and He99
Derivative Instruments and Hedging Activities - Cash Flow Hedges Included in Accumulated Other Comprehensive Loss (Detail) - Interest Rate [Member] - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||
Accumulated Other Comprehensive Loss After-tax | $ 8 | $ 9 |
Portion Expected to be Reclassified to Income during the Next 12 Months | $ 1 | $ 1 |
Maximum Term | 200 months | 212 months |
Derivative Instruments and H100
Derivative Instruments and Hedging Activities - Net Unrealized and Realized Derivative Gains (Losses) Deferred as Regulatory Liabilities and Regulatory Assets (Detail) - Other Derivative Activity [Member] - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Derivative Instruments, Gain (Loss) [Line Items] | |||
Net unrealized (loss) gain arising during the period | $ (3) | $ (3) | $ 4 |
Net realized (loss) gain recognized during the period | (5) | 2 | (4) |
Delmarva Power & Light Co/De [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Net unrealized (loss) gain arising during the period | (3) | (3) | 1 |
Net realized (loss) gain recognized during the period | $ (5) | $ 2 | $ (4) |
Derivative Instruments and H101
Derivative Instruments and Hedging Activities - Net Outstanding Commodity Forward Contracts That Did Not Qualify For Hedge Accounting (Detail) - Natural Gas [Member] - Long [Member] - Other Derivative Instruments [Member] - MMBTU | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Derivative [Line Items] | ||
Quantity | 4,190,000 | 3,892,500 |
Delmarva Power & Light Co/De [Member] | ||
Derivative [Line Items] | ||
Quantity | 4,190,000 | 3,892,500 |
Derivative Instruments and H102
Derivative Instruments and Hedging Activities - Additional Information (Detail) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended |
Sep. 30, 2015 | Dec. 31, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
Net unrealized gain on derivative assets | $ 15 | $ 15 |
Fair Value Disclosures - Fair V
Fair Value Disclosures - Fair Value of Financial Assets and Liabilities Measured on Recurring Basis (Detail) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Financial instruments, assets | $ 133 | $ 122 |
Financial instruments, liabilities | 32 | 34 |
Preferred Stock [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Derivative instruments, assets | 18 | 3 |
Treasury Funds [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Cash equivalents and restricted cash equivalents | 42 | |
Restricted cash equivalents | 38 | |
Money Market Funds and Short-term Investments [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Executive deferred compensation plan assets | 27 | 35 |
Life Insurance Contracts [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Executive deferred compensation plan assets | 46 | 46 |
Executive deferred compensation plan liabilities | 30 | 30 |
Natural Gas [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Derivative instruments, liabilities | 2 | 4 |
Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Financial instruments, assets | 54 | 52 |
Financial instruments, liabilities | 2 | 4 |
Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Treasury Funds [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Cash equivalents and restricted cash equivalents | 42 | |
Restricted cash equivalents | 38 | |
Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Money Market Funds and Short-term Investments [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Executive deferred compensation plan assets | 12 | 14 |
Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Natural Gas [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Derivative instruments, liabilities | 2 | 4 |
Significant Other Observable Inputs (Level 2) [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Financial instruments, assets | 42 | 48 |
Financial instruments, liabilities | 30 | 30 |
Significant Other Observable Inputs (Level 2) [Member] | Money Market Funds and Short-term Investments [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Executive deferred compensation plan assets | 15 | 21 |
Significant Other Observable Inputs (Level 2) [Member] | Life Insurance Contracts [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Executive deferred compensation plan assets | 27 | 27 |
Executive deferred compensation plan liabilities | 30 | 30 |
Significant Unobservable Inputs (Level 3) [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Financial instruments, assets | 37 | 22 |
Significant Unobservable Inputs (Level 3) [Member] | Preferred Stock [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Derivative instruments, assets | 18 | 3 |
Significant Unobservable Inputs (Level 3) [Member] | Life Insurance Contracts [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Executive deferred compensation plan assets | 19 | 19 |
Potomac Electric Power Co [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Financial instruments, assets | 70 | 80 |
Financial instruments, liabilities | 6 | 7 |
Potomac Electric Power Co [Member] | Treasury Funds [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Cash equivalents and restricted cash equivalents | 2 | |
Restricted cash equivalents | 5 | |
Potomac Electric Power Co [Member] | Money Market Funds and Short-term Investments [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Executive deferred compensation plan assets | 26 | 34 |
Potomac Electric Power Co [Member] | Life Insurance Contracts [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Executive deferred compensation plan assets | 42 | 41 |
Executive deferred compensation plan liabilities | 6 | 7 |
Potomac Electric Power Co [Member] | Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Financial instruments, assets | 13 | 18 |
Potomac Electric Power Co [Member] | Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Treasury Funds [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Cash equivalents and restricted cash equivalents | 2 | |
Restricted cash equivalents | 5 | |
Potomac Electric Power Co [Member] | Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Money Market Funds and Short-term Investments [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Executive deferred compensation plan assets | 11 | 13 |
Potomac Electric Power Co [Member] | Significant Other Observable Inputs (Level 2) [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Financial instruments, assets | 38 | 44 |
Financial instruments, liabilities | 6 | 7 |
Potomac Electric Power Co [Member] | Significant Other Observable Inputs (Level 2) [Member] | Money Market Funds and Short-term Investments [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Executive deferred compensation plan assets | 15 | 21 |
Potomac Electric Power Co [Member] | Significant Other Observable Inputs (Level 2) [Member] | Life Insurance Contracts [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Executive deferred compensation plan assets | 23 | 23 |
Executive deferred compensation plan liabilities | 6 | 7 |
Potomac Electric Power Co [Member] | Significant Unobservable Inputs (Level 3) [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Financial instruments, assets | 19 | 18 |
Potomac Electric Power Co [Member] | Significant Unobservable Inputs (Level 3) [Member] | Life Insurance Contracts [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Executive deferred compensation plan assets | 19 | 18 |
Delmarva Power & Light Co/De [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Financial instruments, assets | 7 | |
Financial instruments, liabilities | 3 | 5 |
Delmarva Power & Light Co/De [Member] | Treasury Funds [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Restricted cash equivalents | 5 | |
Delmarva Power & Light Co/De [Member] | Life Insurance Contracts [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Executive deferred compensation plan assets | 1 | |
Executive deferred compensation plan liabilities | 1 | 1 |
Delmarva Power & Light Co/De [Member] | Natural Gas [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Derivative instruments, liabilities | 2 | 4 |
Delmarva Power & Light Co/De [Member] | Money Market Funds [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Executive deferred compensation plan assets | 1 | |
Delmarva Power & Light Co/De [Member] | Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Financial instruments, assets | 6 | |
Financial instruments, liabilities | 2 | 4 |
Delmarva Power & Light Co/De [Member] | Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Treasury Funds [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Restricted cash equivalents | 5 | |
Delmarva Power & Light Co/De [Member] | Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Natural Gas [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Derivative instruments, liabilities | 2 | 4 |
Delmarva Power & Light Co/De [Member] | Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Money Market Funds [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Executive deferred compensation plan assets | 1 | |
Delmarva Power & Light Co/De [Member] | Significant Other Observable Inputs (Level 2) [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Financial instruments, liabilities | 1 | 1 |
Delmarva Power & Light Co/De [Member] | Significant Other Observable Inputs (Level 2) [Member] | Life Insurance Contracts [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Executive deferred compensation plan liabilities | 1 | 1 |
Delmarva Power & Light Co/De [Member] | Significant Unobservable Inputs (Level 3) [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Financial instruments, assets | 1 | |
Delmarva Power & Light Co/De [Member] | Significant Unobservable Inputs (Level 3) [Member] | Life Insurance Contracts [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Executive deferred compensation plan assets | 1 | |
Atlantic City Electric Co [Member] | Treasury Funds [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Cash equivalents and restricted cash equivalents | 30 | 24 |
Atlantic City Electric Co [Member] | Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Treasury Funds [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Cash equivalents and restricted cash equivalents | $ 30 | $ 24 |
Fair Value Disclosures - Reconc
Fair Value Disclosures - Reconciliations of Fair Value Measurements Using Significant Unobservable Inputs (Level 3) (Detail) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Preferred Stock [Member] | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Beginning balance | $ 3 | |
Included in income | 15 | |
Included in accumulated other comprehensive loss | 0 | $ 0 |
Included in regulatory liabilities | 0 | 0 |
Purchases | 0 | 0 |
Issuances | 3 | |
Transfers in (out) of Level 3 | 0 | 0 |
Ending balance | 18 | 3 |
Life Insurance Contracts [Member] | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Beginning balance | 19 | 19 |
Included in income | 5 | 3 |
Included in accumulated other comprehensive loss | 0 | 0 |
Included in regulatory liabilities | 0 | 0 |
Purchases | 0 | 0 |
Issuances | (3) | (3) |
Settlements | (2) | |
Transfers in (out) of Level 3 | 0 | 0 |
Ending balance | 19 | 19 |
Life Insurance Contracts [Member] | Potomac Electric Power Co [Member] | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Beginning balance | 18 | 18 |
Included in income | 5 | 3 |
Included in accumulated other comprehensive loss | 0 | 0 |
Purchases | 0 | 0 |
Issuances | (3) | (3) |
Settlements | (1) | |
Transfers in (out) of Level 3 | 0 | 0 |
Ending balance | 19 | 18 |
Life Insurance Contracts [Member] | Delmarva Power & Light Co/De [Member] | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Beginning balance | 1 | 1 |
Included in accumulated other comprehensive loss | 0 | 0 |
Included in regulatory liabilities | 0 | 0 |
Purchases | 0 | 0 |
Settlements | (1) | |
Transfers in (out) of Level 3 | $ 0 | 0 |
Ending balance | $ 1 |
Fair Value Disclosures - Gains
Fair Value Disclosures - Gains on Level 3 Instruments Included in Income (Detail) - Other Income [Member] - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total gains included in income for the period | $ 20 | $ 3 |
Change in unrealized gains relating to assets still held at reporting date | 18 | 3 |
Potomac Electric Power Co [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total gains included in income for the period | 5 | 3 |
Change in unrealized gains relating to assets still held at reporting date | $ 3 | $ 3 |
Fair Value Disclosures - Fai106
Fair Value Disclosures - Fair Value of Financial Liabilities Measured on Recurring Basis (Detail) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term debt, Fair Value | $ 5,523 | $ 5,583 |
Transition Bonds, Fair Value | 185 | 235 |
Long-term project funding, Fair Value | 5 | 28 |
Total Liabilities, Fair Value | 5,713 | 5,846 |
Significant Other Observable Inputs (Level 2) [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term debt, Fair Value | 4,941 | 5,136 |
Transition Bonds, Fair Value | 185 | 235 |
Total Liabilities, Fair Value | 5,126 | 5,371 |
Significant Unobservable Inputs (Level 3) [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term debt, Fair Value | 582 | 447 |
Long-term project funding, Fair Value | 5 | 28 |
Total Liabilities, Fair Value | 587 | 475 |
Potomac Electric Power Co [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term debt, Fair Value | 2,673 | 2,624 |
Total Liabilities, Fair Value | 2,636 | |
Short-term project funding, Fair Value | 12 | |
Potomac Electric Power Co [Member] | Significant Other Observable Inputs (Level 2) [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term debt, Fair Value | 2,673 | 2,624 |
Total Liabilities, Fair Value | 2,624 | |
Potomac Electric Power Co [Member] | Significant Unobservable Inputs (Level 3) [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Total Liabilities, Fair Value | 12 | |
Short-term project funding, Fair Value | 12 | |
Delmarva Power & Light Co/De [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term debt, Fair Value | 1,183 | 1,123 |
Delmarva Power & Light Co/De [Member] | Significant Other Observable Inputs (Level 2) [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term debt, Fair Value | 1,080 | 1,016 |
Delmarva Power & Light Co/De [Member] | Significant Unobservable Inputs (Level 3) [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term debt, Fair Value | 103 | 107 |
Atlantic City Electric Co [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term debt, Fair Value | 1,140 | 1,035 |
Transition Bonds, Fair Value | 185 | 235 |
Total Liabilities, Fair Value | 1,325 | 1,270 |
Atlantic City Electric Co [Member] | Significant Other Observable Inputs (Level 2) [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term debt, Fair Value | 860 | 903 |
Transition Bonds, Fair Value | 185 | 235 |
Total Liabilities, Fair Value | 1,045 | 1,138 |
Atlantic City Electric Co [Member] | Significant Unobservable Inputs (Level 3) [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term debt, Fair Value | 280 | 132 |
Total Liabilities, Fair Value | $ 280 | $ 132 |
Fair Value Disclosures - Fai107
Fair Value Disclosures - Fair Value of Financial Liabilities Measured on Recurring Basis (Parenthetical) (Detail) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term debt, carrying amount | $ 4,999 | $ 4,807 |
Transition bonds, carrying amount | 171 | 215 |
Potomac Electric Power Co [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term debt, carrying amount | 2,332 | 2,124 |
Delmarva Power & Light Co/De [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term debt, carrying amount | 1,170 | 1,071 |
Atlantic City Electric Co [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term debt, carrying amount | 1,038 | 903 |
Transition bonds, carrying amount | $ 171 | $ 215 |
Commitments and Contingencies -
Commitments and Contingencies - Retained Environmental Exposures - Additional Information (Detail) | 1 Months Ended | |
Jul. 31, 2010USD ($)Facility | Dec. 31, 2015USD ($) | |
Other Commitments [Line Items] | ||
Loss contingency liabilities | $ 12,000,000 | |
Conectiv Energy [Member] | ||
Other Commitments [Line Items] | ||
Third party maximum and seller floor for environmental remediation costs | $ 10,000,000 | |
Number of facility locations | Facility | 9 | |
Environmental remediation expense minimum | $ 7,000,000 | |
Environmental remediation expense maximum | 18,000,000 | |
PHI [Member] | ||
Other Commitments [Line Items] | ||
Third party maximum and seller floor for environmental remediation costs | $ 10,000,000 | |
Potomac Electric Power Co [Member] | ||
Other Commitments [Line Items] | ||
Loss contingency liabilities | 4,000,000 | |
Delmarva Power & Light Co/De [Member] | ||
Other Commitments [Line Items] | ||
Loss contingency liabilities | 3,000,000 | |
Atlantic City Electric Co [Member] | ||
Other Commitments [Line Items] | ||
Loss contingency liabilities | $ 5,000,000 |
Commitments and Contingencie109
Commitments and Contingencies - Schedule of Accrued Liabilities for Environmental Exposures (Detail) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2015 | |
Other Commitments [Line Items] | ||
Beginning balance | $ 28 | |
Accruals | 10 | |
Payments | (5) | |
Ending balance | 33 | |
Less amounts in Other Current Liabilities | $ 4 | |
Amounts in Other Deferred Credits | 29 | |
Total accrued liabilities for environmental contingencies | 28 | 33 |
Legacy Generation Regulated [Member] | ||
Other Commitments [Line Items] | ||
Beginning balance | 6 | |
Accruals | 3 | |
Payments | (1) | |
Ending balance | 8 | |
Less amounts in Other Current Liabilities | 1 | |
Amounts in Other Deferred Credits | 7 | |
Total accrued liabilities for environmental contingencies | 6 | 8 |
Legacy Generation Non-Regulated [Member] | ||
Other Commitments [Line Items] | ||
Beginning balance | 5 | |
Accruals | 0 | |
Ending balance | 5 | |
Amounts in Other Deferred Credits | 5 | |
Total accrued liabilities for environmental contingencies | 5 | 5 |
Potomac Electric Power Co [Member] | ||
Other Commitments [Line Items] | ||
Beginning balance | 19 | |
Accruals | 7 | |
Payments | (2) | |
Ending balance | 24 | |
Less amounts in Other Current Liabilities | 2 | |
Amounts in Other Deferred Credits | 22 | |
Total accrued liabilities for environmental contingencies | 19 | 24 |
Potomac Electric Power Co [Member] | Legacy Generation Regulated [Member] | ||
Other Commitments [Line Items] | ||
Beginning balance | 3 | |
Accruals | 3 | |
Ending balance | 6 | |
Amounts in Other Deferred Credits | 6 | |
Total accrued liabilities for environmental contingencies | 3 | 6 |
Delmarva Power & Light Co/De [Member] | ||
Other Commitments [Line Items] | ||
Beginning balance | 3 | |
Accruals | 3 | |
Payments | (3) | |
Ending balance | 3 | |
Less amounts in Other Current Liabilities | 2 | |
Amounts in Other Deferred Credits | 1 | |
Total accrued liabilities for environmental contingencies | 3 | 3 |
Delmarva Power & Light Co/De [Member] | Legacy Generation Regulated [Member] | ||
Other Commitments [Line Items] | ||
Beginning balance | 2 | |
Payments | (1) | |
Ending balance | 1 | |
Less amounts in Other Current Liabilities | 1 | |
Total accrued liabilities for environmental contingencies | 2 | 1 |
Atlantic City Electric Co [Member] | Legacy Generation Regulated [Member] | ||
Other Commitments [Line Items] | ||
Beginning balance | 1 | |
Accruals | 0 | |
Payments | 0 | |
Ending balance | 1 | |
Amounts in Other Deferred Credits | 1 | |
Total accrued liabilities for environmental contingencies | 1 | 1 |
Transmission and Distribution [Member] | ||
Other Commitments [Line Items] | ||
Beginning balance | 17 | |
Accruals | 7 | |
Payments | (4) | |
Ending balance | 20 | |
Less amounts in Other Current Liabilities | 3 | |
Amounts in Other Deferred Credits | 17 | |
Total accrued liabilities for environmental contingencies | 17 | 20 |
Transmission and Distribution [Member] | Potomac Electric Power Co [Member] | ||
Other Commitments [Line Items] | ||
Beginning balance | 16 | |
Accruals | 4 | |
Payments | (2) | |
Ending balance | 18 | |
Less amounts in Other Current Liabilities | 2 | |
Amounts in Other Deferred Credits | 16 | |
Total accrued liabilities for environmental contingencies | 16 | 18 |
Transmission and Distribution [Member] | Delmarva Power & Light Co/De [Member] | ||
Other Commitments [Line Items] | ||
Beginning balance | 1 | |
Accruals | 3 | |
Payments | (2) | |
Ending balance | 2 | |
Less amounts in Other Current Liabilities | 1 | |
Amounts in Other Deferred Credits | 1 | |
Total accrued liabilities for environmental contingencies | $ 1 | $ 2 |
Commitments and Contingencie110
Commitments and Contingencies - Environmental Matters - Additional Information (Detail) | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||||
Aug. 31, 2015gal | Mar. 31, 2014USD ($) | Jul. 31, 2013USD ($) | Jan. 31, 2011USD ($)gal | Nov. 30, 2008USD ($) | Mar. 31, 2013USD ($) | Dec. 31, 2015USD ($) | |
Other Commitments [Line Items] | |||||||
Estimated costs remaining to remediate the site | $ 6,000,000 | ||||||
Quantity of mineral oil spill | gal | 4,500 | ||||||
Cost of litigation | $ 875,000 | ||||||
Civil penalty payment | 250,000 | ||||||
Donation for training fund | 25,000 | ||||||
Fund provided for installation and operation of the trash collection SEP | 600,000 | ||||||
Tax payment made | $ 74,000,000 | $ 74,000,000 | |||||
Income tax penalties | 1,000,000 | 0 | |||||
Interest expense assessed relating to disallowed deductions | $ 28,000,000 | ||||||
Non-cash charge (after-tax) | $ 377,000,000 | ||||||
Maximum tax penalty percentage | 20.00% | ||||||
Percentage of disallowed tax benefits associated with leases | 100.00% | ||||||
Federal income tax benefits | $ 192,000,000 | ||||||
Potential interest on potential tax liability related to disallowed tax benefits | 50,000,000 | ||||||
Deposit of additional taxes and related interest | 242,000,000 | ||||||
U.S. Environmental Protection Agency [Member] | |||||||
Other Commitments [Line Items] | |||||||
Costs to date to clean up site | 6,000,000 | ||||||
Minimum [Member] | |||||||
Other Commitments [Line Items] | |||||||
Cost of implementation of a closure plan and cap | $ 9,000,000 | ||||||
Maximum [Member] | |||||||
Other Commitments [Line Items] | |||||||
Cost of implementation of a closure plan and cap | 13,000,000 | ||||||
PHI [Member] | |||||||
Other Commitments [Line Items] | |||||||
Mineral oil released | gal | 6,100 | ||||||
Released mineral oil recovered through remediation efforts, percentage | 80.00% | ||||||
PHI [Member] | Minimum [Member] | |||||||
Other Commitments [Line Items] | |||||||
Cost of implementation of a closure plan and cap | 3,000,000 | ||||||
Proposed compensation for damages | $ 106,000 | ||||||
PHI [Member] | Maximum [Member] | |||||||
Other Commitments [Line Items] | |||||||
Cost of implementation of a closure plan and cap | 6,000,000 | ||||||
Proposed compensation for damages | 161,000 | ||||||
Potomac Electric Power Co [Member] | |||||||
Other Commitments [Line Items] | |||||||
Quantity of mineral oil spill | gal | 4,500 | ||||||
Cost of litigation | 875,000 | ||||||
Civil penalty payment | 250,000 | ||||||
Donation for training fund | 25,000 | ||||||
Fund provided for installation and operation of the trash collection SEP | $ 600,000 | ||||||
Mineral oil released | gal | 6,100 | ||||||
Released mineral oil recovered through remediation efforts, percentage | 80.00% | ||||||
Non-cash charge (after-tax) | 377,000,000 | ||||||
Potomac Electric Power Co [Member] | Minimum [Member] | |||||||
Other Commitments [Line Items] | |||||||
Cost of implementation of a closure plan and cap | 3,000,000 | ||||||
Proposed compensation for damages | 106,000 | ||||||
Potomac Electric Power Co [Member] | Minimum [Member] | Environmental Protection Agency [Member] | |||||||
Other Commitments [Line Items] | |||||||
Cost of implementation of a closure plan and cap | 8,000,000 | ||||||
Potomac Electric Power Co [Member] | Maximum [Member] | |||||||
Other Commitments [Line Items] | |||||||
Cost of implementation of a closure plan and cap | 6,000,000 | ||||||
Proposed compensation for damages | $ 161,000 | ||||||
Potomac Electric Power Co [Member] | Maximum [Member] | Environmental Protection Agency [Member] | |||||||
Other Commitments [Line Items] | |||||||
Cost of implementation of a closure plan and cap | $ 12,000,000 | ||||||
Atlantic City Electric Co [Member] | |||||||
Other Commitments [Line Items] | |||||||
Estimated costs remaining to remediate the site | 6,000,000 | ||||||
Non-cash charge (after-tax) | $ 377,000,000 | ||||||
Atlantic City Electric Co [Member] | U.S. Environmental Protection Agency [Member] | |||||||
Other Commitments [Line Items] | |||||||
Costs to date to clean up site | $ 6,000,000 |
Commitments and Contingencie111
Commitments and Contingencies - Schedule of Commitments and Obligations (Detail) $ in Millions | Dec. 31, 2015USD ($) |
Other Commitments [Line Items] | |
Guarantees associated with disposal of Conectiv Energy assets | $ 13 |
Guaranteed lease residual values | 19 |
Total | 32 |
PHI [Member] | |
Other Commitments [Line Items] | |
Guarantees associated with disposal of Conectiv Energy assets | 13 |
Guaranteed lease residual values | 3 |
Total | 16 |
Potomac Electric Power Co [Member] | |
Other Commitments [Line Items] | |
Guaranteed lease residual values | 5 |
Total | 5 |
Delmarva Power & Light Co/De [Member] | |
Other Commitments [Line Items] | |
Guaranteed lease residual values | 6 |
Total | 6 |
Atlantic City Electric Co [Member] | |
Other Commitments [Line Items] | |
Guaranteed lease residual values | 5 |
Total | $ 5 |
Commitments and Contingencie112
Commitments and Contingencies - Schedule of Commitments and Obligations (Parenthetical) (Detail) | 12 Months Ended |
Dec. 31, 2015USD ($) | |
Other Commitments [Line Items] | |
Derivative portfolio guarantee | $ 13,000,000 |
Obligations under guarantee | $ 52,000,000 |
Minimum [Member] | |
Other Commitments [Line Items] | |
Lease term range | 1 year |
Lease term range | 3 years |
Maximum [Member] | |
Other Commitments [Line Items] | |
Lease term range | 4 years |
Lease term range | 8 years |
PHI [Member] | |
Other Commitments [Line Items] | |
Obligations under guarantee | $ 9,000,000 |
Potomac Electric Power Co [Member] | |
Other Commitments [Line Items] | |
Obligations under guarantee | 13,000,000 |
Delmarva Power & Light Co/De [Member] | |
Other Commitments [Line Items] | |
Obligations under guarantee | 16,000,000 |
Atlantic City Electric Co [Member] | |
Other Commitments [Line Items] | |
Obligations under guarantee | 14,000,000 |
Leased Equipment and Fleet Vehicles [Member] | |
Other Commitments [Line Items] | |
Fair value of leased equipment and vehicles | $ 0 |
Commitments and Contingencie113
Commitments and Contingencies - Tax Legislation, Guarantees, Indemnifications, and Performance Contracts - Additional Information (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Other Commitments [Line Items] | |||
Contractual obligations due in 2016 | $ 268 | ||
Contractual obligations due in 2017 to 2018 | 469 | ||
Contractual obligations due in 2019 to 2020 | 472 | ||
Contractual obligations due, thereafter | 993 | ||
Rental expense for operating leases | 60 | $ 59 | $ 54 |
Future minimum operating lease payments, 2016 | 52 | ||
Future minimum operating lease payments, 2017 | 48 | ||
Future minimum operating lease payments, 2018 | 47 | ||
Future minimum operating lease payments, 2019 | 34 | ||
Future minimum operating lease payments, 2020 | 37 | ||
Future minimum operating lease payments, thereafter | $ 304 | ||
Pepco Energy Services [Member] | Energy Savings or Combined Heat and Power Performance [Member] | |||
Other Commitments [Line Items] | |||
Contract life, maximum remaining term | 20 years | ||
Value of guarantees under construction projects | $ 15 | ||
Accrued liability on contracts | 1 | ||
Pepco Energy Services [Member] | Completed Performance Contracts Associated With Savings Guarantees [Member] | |||
Other Commitments [Line Items] | |||
Value of guarantees completed projects | $ 221 | ||
Contract life, maximum remaining term | 23 years | ||
Pepco Energy Services [Member] | Uncompleted Performance Contracts Associated With Savings Guarantees [Member] | |||
Other Commitments [Line Items] | |||
Value of guarantees on projects under construction | $ 55 | ||
Maximum term of project under construction | 19 years | ||
Potomac Electric Power Co [Member] | |||
Other Commitments [Line Items] | |||
Rental expense for operating leases | $ 7 | 8 | 7 |
Future minimum operating lease payments, 2016 | 7 | ||
Future minimum operating lease payments, 2017 | 6 | ||
Future minimum operating lease payments, 2018 | 5 | ||
Future minimum operating lease payments, 2019 | 4 | ||
Future minimum operating lease payments, 2020 | 3 | ||
Future minimum operating lease payments, thereafter | 7 | ||
Delmarva Power & Light Co/De [Member] | |||
Other Commitments [Line Items] | |||
Contractual obligations due in 2016 | 64 | ||
Contractual obligations due in 2017 to 2018 | 127 | ||
Contractual obligations due in 2019 to 2020 | 128 | ||
Contractual obligations due, thereafter | 296 | ||
Rental expense for operating leases | 14 | 14 | 13 |
Future minimum operating lease payments, 2016 | 13 | ||
Future minimum operating lease payments, 2017 | 12 | ||
Future minimum operating lease payments, 2018 | 16 | ||
Future minimum operating lease payments, 2019 | 6 | ||
Future minimum operating lease payments, 2020 | 9 | ||
Future minimum operating lease payments, thereafter | $ 118 | ||
Ownership interest | 11.90% | ||
Present value of future minimum lease payments | $ 75 | ||
Atlantic City Electric Co [Member] | |||
Other Commitments [Line Items] | |||
Contractual obligations due in 2016 | 203 | ||
Contractual obligations due in 2017 to 2018 | 341 | ||
Contractual obligations due in 2019 to 2020 | 344 | ||
Contractual obligations due, thereafter | 697 | ||
Rental expense for operating leases | 13 | $ 12 | $ 12 |
Future minimum operating lease payments, 2016 | 8 | ||
Future minimum operating lease payments, 2017 | 8 | ||
Future minimum operating lease payments, 2018 | 7 | ||
Future minimum operating lease payments, 2019 | 6 | ||
Future minimum operating lease payments, 2020 | 6 | ||
Future minimum operating lease payments, thereafter | $ 30 |
Variable Interest Entities - Ad
Variable Interest Entities - Additional Information (Detail) $ in Millions | Oct. 18, 2011MW | Dec. 31, 2015USD ($)MWhAgreementMW | Dec. 31, 2014USD ($)MWhMW | Dec. 31, 2013USD ($) |
Delmarva Power & Light Co/De [Member] | ||||
Variable Interest Entity [Line Items] | ||||
Power produced by fuel cell facility | 30 | |||
Power produced by fuel cell facility | MWh | 227,113 | 222,948 | ||
Delmarva Power & Light Co/De [Member] | Fuel Cell Facility [Member] | ||||
Variable Interest Entity [Line Items] | ||||
Term of agreement | Through 2,033 | |||
Amount billed to distribution customers, respect to energy produced by these facilities | $ | $ 37 | $ 36 | $ 23 | |
Delmarva Power & Light Co/De [Member] | Wind PPA [Member] | ||||
Variable Interest Entity [Line Items] | ||||
Purchased energy | $ | $ 29 | $ 31 | 30 | |
Delmarva Power & Light Co/De [Member] | Wind PPA [Member] | Wind Facility One [Member] | ||||
Variable Interest Entity [Line Items] | ||||
Energy purchase maximum to be purchased | 50 | |||
Delmarva Power & Light Co/De [Member] | Wind PPA [Member] | Wind Facility Two [Member] | ||||
Variable Interest Entity [Line Items] | ||||
Energy purchase maximum to be purchased | 40 | |||
Delmarva Power & Light Co/De [Member] | Wind PPA [Member] | Wind Facility Three [Member] | ||||
Variable Interest Entity [Line Items] | ||||
Energy purchase maximum to be purchased | 38 | |||
Delmarva Power & Light Co/De [Member] | Solar PPA [Member] | ||||
Variable Interest Entity [Line Items] | ||||
Megawatts received from power purchase agreements (PPAs) | 10 | |||
Number of purchase power agreements | Agreement | 1 | |||
Energy purchase maximum to be purchased | 28 | 19 | ||
Term of agreement | Through 2,030 | |||
Term of agreement, years | 20 years | |||
Obligated purchase amount of energy produced at the facility | 70.00% | |||
Solar energy purchases | $ | $ 6 | $ 6 | 3 | |
Delmarva Power & Light Co/De [Member] | Land-Based Wind PPA [Member] | ||||
Variable Interest Entity [Line Items] | ||||
Megawatts received from power purchase agreements (PPAs) | 128 | |||
Number of purchase power agreements | Agreement | 3 | |||
Delmarva Power & Light Co/De [Member] | 2015 PPA [Member] | Maximum [Member] | ||||
Variable Interest Entity [Line Items] | ||||
Expected time frame for facilities to be operational | 1 year | |||
Atlantic City Electric Co [Member] | ||||
Variable Interest Entity [Line Items] | ||||
Purchase activities with non utility generators per power purchase agreements | $ | $ 198 | 208 | 206 | |
Equity ownership percentage | 100.00% | |||
Atlantic City Electric Co [Member] | Non-Utility Generators [Member] | ||||
Variable Interest Entity [Line Items] | ||||
Megawatts received from power purchase agreements (PPAs) | 459 | |||
Number of purchase power agreements | Agreement | 3 | |||
Purchased energy | $ | $ 208 | $ 233 | $ 221 |
Accumulated Other Comprehens115
Accumulated Other Comprehensive Loss - Schedule of Components of Other Comprehensive Loss (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Balance at beginning of period | $ (46) | $ (34) | $ (48) |
Amount of amortization of net prior service cost and actuarial loss reclassified to Other operation and maintenance expense | 15 | (20) | 13 |
Amount of net pre-tax loss reclassified to Income (loss) from discontinued operations before income tax | 1 | 1 | 1 |
Balance at end of period | (36) | (46) | (34) |
Pension and Other Postretirement Benefits [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Balance at beginning of period | (37) | (25) | (32) |
Amount of amortization of net prior service cost and actuarial loss reclassified to Other operation and maintenance expense | 6 | 5 | 5 |
Amount of net prior service cost and actuarial gain (loss) arising during the year | 9 | (25) | 8 |
Income tax (benefit) expense | 6 | (8) | 6 |
Balance at end of period | (28) | (37) | (25) |
Treasury Lock [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Balance at beginning of period | (9) | (9) | (10) |
Amount of pre-tax loss reclassified to Interest expense | 1 | 1 | 1 |
Income tax (benefit) expense | 1 | ||
Balance at end of period | $ (8) | $ (9) | (9) |
Commodity Derivatives [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Balance at beginning of period | (6) | ||
Amount of net pre-tax loss reclassified to Income (loss) from discontinued operations before income tax | 10 | ||
Income tax (benefit) expense | $ 4 |
Quarterly Financial Informat116
Quarterly Financial Information - Schedule of Quarterly Financial Information (Detail) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Quarterly Financial Information [Line Items] | |||||||||||
Total Operating Revenue | $ 1,150 | $ 1,362 | $ 1,140 | $ 1,371 | $ 1,118 | $ 1,313 | $ 1,117 | $ 1,330 | $ 5,023 | $ 4,878 | $ 4,666 |
Total operating expenses | 941 | 1,179 | 1,001 | 1,229 | 1,004 | 1,147 | 966 | 1,157 | 4,350 | 4,274 | 3,998 |
Operating Income (Loss) | 209 | 183 | 139 | 142 | 114 | 166 | 151 | 173 | 673 | 604 | 668 |
Other Expenses | (65) | (43) | (59) | (59) | (66) | (53) | (53) | (52) | (226) | (224) | (239) |
Income Before Income Tax Expense | 144 | 140 | 80 | 83 | 48 | 113 | 98 | 121 | 447 | 380 | 429 |
Income Tax Expense | 23 | 49 | 27 | 30 | 13 | 34 | 45 | 46 | 129 | 138 | 319 |
Net Income from Continuing Operations | 121 | 91 | 53 | 53 | 318 | 242 | 110 | ||||
Income from Discontinued Operations, net of taxes | 9 | 9 | (322) | ||||||||
Net Income | $ 130 | $ 91 | $ 53 | $ 53 | $ 35 | $ 79 | $ 53 | $ 75 | $ 327 | $ 242 | $ (212) |
Earnings Per Share of Common Stock from Continuing Operations | $ 0.48 | $ 0.36 | $ 0.21 | $ 0.21 | $ 1.25 | ||||||
Earnings Per Share of Common Stock from Discontinued Operations | 0.03 | 0.04 | |||||||||
Basic and Diluted Earnings Per Share of | 0.51 | 0.36 | 0.21 | 0.21 | $ 0.14 | $ 0.31 | $ 0.21 | $ 0.30 | 1.29 | $ 0.96 | |
Cash Dividends Per Share of Common Stock | $ 0.27 | $ 0.27 | $ 0.27 | $ 0.27 | $ 0.27 | $ 0.27 | $ 0.27 | $ 0.27 | $ 1.08 | $ 1.08 | $ 1.08 |
Atlantic City Electric Co [Member] | |||||||||||
Quarterly Financial Information [Line Items] | |||||||||||
Total operating expenses | $ 252 | $ 349 | $ 254 | $ 313 | $ 246 | $ 295 | $ 228 | $ 309 | $ 1,168 | $ 1,078 | $ 1,066 |
Operating Income (Loss) | 40 | 38 | 32 | 20 | 27 | 52 | 25 | 31 | 130 | 135 | 136 |
Other Expenses | (15) | (17) | (15) | (14) | (17) | (15) | (15) | (15) | (61) | (62) | (67) |
Income Before Income Tax Expense | 25 | 21 | 17 | 6 | 10 | 37 | 10 | 16 | 69 | 73 | 69 |
Income Tax Expense | 15 | 7 | 7 | 2 | 4 | 14 | 4 | 6 | 31 | 28 | 19 |
Net Income | 10 | 14 | 10 | 4 | 6 | 23 | 6 | 10 | 38 | 45 | 50 |
Total Operating Revenue | 292 | 387 | 286 | 333 | 273 | 347 | 253 | 340 | 1,298 | 1,213 | 1,202 |
Potomac Electric Power Co [Member] | |||||||||||
Quarterly Financial Information [Line Items] | |||||||||||
Total operating expenses | 379 | 497 | 435 | 493 | 408 | 462 | 414 | 469 | 1,804 | 1,753 | 1,705 |
Operating Income (Loss) | 124 | 115 | 83 | 63 | 63 | 125 | 94 | 66 | 385 | 348 | 321 |
Other Expenses | (29) | (23) | (23) | (25) | (27) | (20) | (20) | (18) | (100) | (85) | (92) |
Income Before Income Tax Expense | 95 | 92 | 60 | 38 | 36 | 105 | 74 | 48 | 285 | 263 | 229 |
Income Tax Expense | 36 | 32 | 18 | 12 | 10 | 38 | 28 | 16 | 98 | 92 | 79 |
Net Income | 59 | 60 | 42 | 26 | 26 | 67 | 46 | 32 | 187 | 171 | 150 |
Total Operating Revenue | 503 | 612 | 518 | 556 | 471 | 587 | 508 | 535 | 2,189 | 2,101 | 2,026 |
Delmarva Power & Light Co/De [Member] | |||||||||||
Quarterly Financial Information [Line Items] | |||||||||||
Total operating expenses | 256 | 285 | 251 | 361 | 257 | 264 | 239 | 326 | 1,153 | 1,086 | 1,059 |
Operating Income (Loss) | 47 | 32 | 24 | 62 | 51 | 45 | 40 | 71 | 165 | 207 | 185 |
Other Expenses | (12) | (8) | (11) | (9) | (12) | (9) | (8) | (9) | (40) | (38) | (40) |
Income Before Income Tax Expense | 35 | 24 | 13 | 53 | 39 | 36 | 32 | 62 | 125 | 169 | 145 |
Income Tax Expense | 14 | 9 | 5 | 21 | 14 | 13 | 13 | 25 | 49 | 65 | 56 |
Net Income | 21 | 15 | 8 | 32 | 25 | 23 | 19 | 37 | 76 | 104 | 89 |
Total Operating Revenue | $ 303 | $ 317 | $ 275 | $ 423 | $ 308 | $ 309 | $ 279 | $ 397 | $ 1,318 | $ 1,293 | $ 1,244 |
Quarterly Financial Informat117
Quarterly Financial Information - Schedule of Quarterly Financial Information (Parenthetical) (Detail) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Quarterly Financial Information [Line Items] | |||||||||||
Increase in fair value of preferred stock derivative | $ 15 | $ 15 | |||||||||
Increase in fair value of preferred stock derivative, after-tax | 10 | ||||||||||
Pretax gains on sales of land | $ 46 | 46 | |||||||||
Aftertax gains on sales of land | 27 | ||||||||||
Income tax benefit | 23 | 49 | $ 27 | $ 30 | $ 13 | $ 34 | $ 45 | $ 46 | 129 | $ 138 | $ 319 |
Charge to correct prior period error after-tax | 7 | ||||||||||
Tax Settlement [Member] | |||||||||||
Quarterly Financial Information [Line Items] | |||||||||||
Income tax benefit | (47) | ||||||||||
Income tax benefit discontinued operations | (9) | ||||||||||
Pepco Energy Services [Member] | |||||||||||
Quarterly Financial Information [Line Items] | |||||||||||
Impairment losses, pre-tax | 28 | 53 | |||||||||
Impairment losses, after-tax | 16 | 32 | |||||||||
Atlantic City Electric Co [Member] | |||||||||||
Quarterly Financial Information [Line Items] | |||||||||||
Income tax benefit | 15 | 7 | 7 | 2 | 4 | 14 | 4 | 6 | 31 | 28 | 19 |
Charge to correct prior period error after-tax | 2 | 2 | |||||||||
Reversed unbilled revenue, pre-tax | 3 | ||||||||||
Reversed unbilled revenue, after-tax | 2 | ||||||||||
Charge to correct prior period error before tax | 3 | ||||||||||
Atlantic City Electric Co [Member] | Tax Settlement [Member] | |||||||||||
Quarterly Financial Information [Line Items] | |||||||||||
Income tax benefit | 3 | ||||||||||
Potomac Electric Power Co [Member] | |||||||||||
Quarterly Financial Information [Line Items] | |||||||||||
Pretax gains on sales of land | 46 | 46 | |||||||||
Aftertax gains on sales of land | 27 | ||||||||||
Income tax benefit | 36 | 32 | 18 | 12 | 10 | 38 | 28 | 16 | 98 | 92 | 79 |
Charge to correct prior period error after-tax | 6 | ||||||||||
Interest expense on uncertain tax positions | 3 | ||||||||||
Potomac Electric Power Co [Member] | Tax Settlement [Member] | |||||||||||
Quarterly Financial Information [Line Items] | |||||||||||
Income tax benefit | (9) | ||||||||||
Delmarva Power & Light Co/De [Member] | |||||||||||
Quarterly Financial Information [Line Items] | |||||||||||
Income tax benefit | 14 | $ 9 | $ 5 | $ 21 | $ 14 | $ 13 | $ 13 | $ 25 | 49 | $ 65 | $ 56 |
Delmarva Power & Light Co/De [Member] | Tax Settlement [Member] | |||||||||||
Quarterly Financial Information [Line Items] | |||||||||||
Income tax benefit | $ 3 | $ 3 |
Discontinued Operations - Incom
Discontinued Operations - Income (Loss) from Discontinued Operations, Net of Income Taxes (Detail) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2015 | Dec. 31, 2013 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Income (Loss) from Discontinued Operations, net of Income Taxes | $ 9 | $ 9 | $ (322) |
Cross-Border Energy Lease Investments [Member] | |||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Income (Loss) from Discontinued Operations, net of Income Taxes | $ 9 | (327) | |
Pepco Energy Services' Retail Electric and Natural Gas Supply Businesses [Member] | |||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Income (Loss) from Discontinued Operations, net of Income Taxes | $ 5 |
Discontinued Operations - Addit
Discontinued Operations - Additional Information (Detail) - USD ($) | 1 Months Ended | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||||
Jan. 31, 2011 | Dec. 31, 2015 | Jun. 30, 2013 | Mar. 31, 2013 | Sep. 30, 2013 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||||
After-tax non-cash charges | $ 377,000,000 | ||||||||
After-tax effect of revised lease rerun | 313,000,000 | ||||||||
Penalties on tax settlement | $ 1,000,000 | 0 | |||||||
Pre-tax loss reclassified into Income from Discontinued operations, Before Taxes | $ (1,000,000) | $ (1,000,000) | $ (1,000,000) | ||||||
Cross-Border Energy Lease Investments [Member] | |||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||||
Income tax benefit, income from operations of discontinued operations | $ (9,000,000) | 9,000,000 | 44,000,000 | ||||||
Non-cash pre-tax charge | 373,000,000 | ||||||||
Corporate and Other [Member] | |||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||||
Interest expense on uncertain tax positions | 66,000,000 | ||||||||
Pepco Energy Services [Member] | |||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||||
Derivatives | 0 | 0 | $ 0 | $ 0 | |||||
Discontinued Operations [Member] | |||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||||
After-tax non-cash charges | $ 6,000,000 | 323,000,000 | |||||||
Non-cash pre-tax charge | 373,000,000 | ||||||||
After-tax effect of revised lease rerun | 313,000,000 | ||||||||
After-tax non-cash charge | 16,000,000 | ||||||||
Penalties associated with re-assessment of tax positions | $ 0 | 0 | |||||||
Penalties on tax settlement | $ 0 | ||||||||
Amount of net pre-tax loss arising during the period included in Accumulated Other Comprehensive Loss | $ (10,000,000) | ||||||||
Amount of net tax loss arising during the period included in Accumulated Other Comprehensive Loss | $ (6,000,000) | ||||||||
Pre-tax loss reclassified into Income from Discontinued operations, Before Taxes | $ (6,000,000) | (4,000,000) | |||||||
Net of tax loss reclassified into Income from Discontinued operations, Net of Income Taxes | (2,000,000) | ||||||||
Discontinued Operations [Member] | PHI [Member] | |||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||||
Net pre-tax gain / loss | $ (3,000,000) | ||||||||
Loss on early termination of finance leases held in trust, after-tax | (2,000,000) | ||||||||
After-tax non-cash charge | 70,000,000 | ||||||||
Discontinued Operations [Member] | PHI [Member] | Proceeds From Early Termination [Member] | |||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||||
Aggregate of net cash proceeds (payments) of lease investments | 873,000,000 | ||||||||
Discontinued Operations [Member] | PHI [Member] | Payment Paid From Early Termination [Member] | |||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||||
Aggregate of net cash proceeds (payments) of lease investments | $ 2,000,000,000 | ||||||||
Discontinued Operations [Member] | Power Delivery [Member] | |||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||||
Interest benefit on uncertain tax positions | 12,000,000 | ||||||||
Discontinued Operations [Member] | Other Non-Regulated [Member] | |||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||||
Interest expense on uncertain tax positions | 16,000,000 | ||||||||
Discontinued Operations [Member] | Corporate and Other [Member] | |||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||||
Interest expense on uncertain tax positions | $ 66,000,000 |
Discontinued Operations - Opera
Discontinued Operations - Operating Results for Cross-Border Energy Lease Investments (Detail) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2015 | Dec. 31, 2013 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Income (loss) from discontinued operations, net of income taxes | $ 9 | $ 9 | $ (322) |
Cross-Border Energy Lease Investments [Member] | |||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Operating revenue from PHI's cross-border energy lease investments | 7 | ||
Non-cash charge to reduce carrying value of PHI's cross-border energy lease investments | (373) | ||
Total operating revenue | (366) | ||
Income (loss) from operations of discontinued operations, net of income taxes | 9 | (325) | |
Net losses associated with the early termination of the cross-border energy lease investments, net of income taxes | (2) | ||
Income (loss) from discontinued operations, net of income taxes | $ 9 | $ (327) |
Discontinued Operations - Op121
Discontinued Operations - Operating Results for Cross-Border Energy Lease Investments (Parenthetical) (Detail) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2015 | Dec. 31, 2013 | |
Cross-Border Energy Lease Investments [Member] | |||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Income tax benefit, income from operations of discontinued operations | $ (9) | $ 9 | $ 44 |
Discontinued Operations - Op122
Discontinued Operations - Operating Results for Retail Electric and Natural Gas Supply Businesses (Detail) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2015 | Dec. 31, 2013 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Income from discontinued operations, net of income taxes | $ 9 | $ 9 | $ (322) |
Discontinued Operations [Member] | Pepco Energy Services [Member] | |||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Operating revenue | 84 | ||
Income from operations of discontinued operations, net of income taxes | 4 | ||
Net gains associated with accelerated disposition of retail electric and natural gas contracts, net of income taxes | 1 | ||
Income from discontinued operations, net of income taxes | $ 5 |
Discontinued Operations - Op123
Discontinued Operations - Operating Results for Retail Electric and Natural Gas Supply Businesses (Parenthetical) (Detail) $ in Millions | 12 Months Ended |
Dec. 31, 2013USD ($) | |
Pepco Energy Services [Member] | Discontinued Operations [Member] | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |
Income tax expense (benefit) from discontinued operations | $ 3 |
Discontinued Operations - Deriv
Discontinued Operations - Derivative Gain (Loss) for Retail Electric and Natural Gas Supply Businesses (Detail) - Discontinued Operations [Member] - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Derivative Instruments, Gain (Loss) [Line Items] | |||
Reclassification of mark-to-market to realized on settlement of contracts | $ 10 | ||
Unrealized mark-to-market loss | $ 0 | $ 0 | 0 |
Total net gain | $ 10 |
Segment Information - Additiona
Segment Information - Additional Information (Detail) | 12 Months Ended |
Dec. 31, 2015Segment | |
Potomac Electric Power Co [Member] | |
Segment Reporting Information [Line Items] | |
Number of operating segments | 1 |
Delmarva Power & Light Co/De [Member] | |
Segment Reporting Information [Line Items] | |
Number of operating segments | 1 |
Atlantic City Electric Co [Member] | |
Segment Reporting Information [Line Items] | |
Number of operating segments | 1 |
Related Party Transactions - Ad
Related Party Transactions - Additional Information (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Potomac Electric Power Co [Member] | PHI Service Company [Member] | |||
Related Party Transaction [Line Items] | |||
Costs directly charged or allocated | $ 240 | $ 220 | $ 209 |
Potomac Electric Power Co [Member] | Pepco Energy Services [Member] | |||
Related Party Transaction [Line Items] | |||
Maintenance services | 26 | 30 | 20 |
Delmarva Power & Light Co/De [Member] | PHI Service Company [Member] | |||
Related Party Transaction [Line Items] | |||
Costs directly charged or allocated | 179 | 163 | 154 |
Delmarva Power & Light Co/De [Member] | Pepco Energy Services [Member] | |||
Related Party Transaction [Line Items] | |||
Maintenance services | 3 | 0 | 0 |
Atlantic City Electric Co [Member] | PHI Service Company [Member] | |||
Related Party Transaction [Line Items] | |||
Costs directly charged or allocated | $ 143 | $ 124 | $ 115 |
Related Party Transactions - Sc
Related Party Transactions - Schedule of Related Party Transactions Included in Balance Sheet (Detail) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Potomac Electric Power Co [Member] | ||
Related Party Transaction [Line Items] | ||
Payable to Related Party, Total | $ (30) | $ (30) |
Potomac Electric Power Co [Member] | PHI Service Company [Member] | ||
Related Party Transaction [Line Items] | ||
Payable to Related Party, Total | (25) | (27) |
Potomac Electric Power Co [Member] | Pepco Energy Services [Member] | ||
Related Party Transaction [Line Items] | ||
Payable to Related Party, Total | (4) | (2) |
Potomac Electric Power Co [Member] | Other [Member] | ||
Related Party Transaction [Line Items] | ||
Payable to Related Party, Total | (1) | (1) |
Delmarva Power & Light Co/De [Member] | ||
Related Party Transaction [Line Items] | ||
Payable to Related Party, Total | (20) | (17) |
Delmarva Power & Light Co/De [Member] | PHI Service Company [Member] | ||
Related Party Transaction [Line Items] | ||
Payable to Related Party, Total | (19) | (18) |
Delmarva Power & Light Co/De [Member] | Other [Member] | ||
Related Party Transaction [Line Items] | ||
Payable to Related Party, Total | (1) | 1 |
Atlantic City Electric Co [Member] | ||
Related Party Transaction [Line Items] | ||
Payable to Related Party, Total | (16) | (15) |
Atlantic City Electric Co [Member] | PHI Service Company [Member] | ||
Related Party Transaction [Line Items] | ||
Payable to Related Party, Total | (15) | (14) |
Atlantic City Electric Co [Member] | Other [Member] | ||
Related Party Transaction [Line Items] | ||
Payable to Related Party, Total | $ (1) | $ (1) |
Related Party Transactions -128
Related Party Transactions - Schedule of Related Party Transactions Included in Income Statement (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Delmarva Power & Light Co/De [Member] | PHI Service Company [Member] | |||
Related Party Transaction [Line Items] | |||
Intercompany lease transactions | $ 4 | $ 5 | $ 4 |
Atlantic City Electric Co [Member] | Millennium Account Services LLC (ACE Affiliate) [Member] | |||
Related Party Transaction [Line Items] | |||
Meter reading services provided by Millennium Account Services LLC (an ACE affiliate) | (4) | (4) | (4) |
Atlantic City Electric Co [Member] | PHI Service Company [Member] | |||
Related Party Transaction [Line Items] | |||
Intercompany lease transactions | (1) | (1) | (1) |
Intercompany use revenue | $ 1 | $ 2 | $ 3 |
Schedule I - Condensed Financia
Schedule I - Condensed Financial Information of Parent Company (Statements of Income (Loss)) (Detail) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Condensed Income Statements, Captions [Line Items] | |||||||||||
Operating Revenue | $ 1,150 | $ 1,362 | $ 1,140 | $ 1,371 | $ 1,118 | $ 1,313 | $ 1,117 | $ 1,330 | $ 5,023 | $ 4,878 | $ 4,666 |
Operating Expenses | |||||||||||
Other operation and maintenance | 1,016 | 924 | 851 | ||||||||
Total operating expenses | 941 | 1,179 | 1,001 | 1,229 | 1,004 | 1,147 | 966 | 1,157 | 4,350 | 4,274 | 3,998 |
Operating Income (Loss) | 209 | 183 | 139 | 142 | 114 | 166 | 151 | 173 | 673 | 604 | 668 |
Other Income (Expenses) | |||||||||||
Interest expense | (280) | (268) | (273) | ||||||||
Income from equity investments | 2 | ||||||||||
Other income | 54 | 44 | 32 | ||||||||
Total Other Income (Expenses) | (65) | (43) | (59) | (59) | (66) | (53) | (53) | (52) | (226) | (224) | (239) |
Income from Continuing Operations Before Income Tax | 144 | 140 | 80 | 83 | 48 | 113 | 98 | 121 | 447 | 380 | 429 |
Income Tax Expense Related to Continuing Operations | 23 | 49 | 27 | 30 | 13 | 34 | 45 | 46 | 129 | 138 | 319 |
Net Income from Continuing Operations | 121 | 91 | 53 | 53 | 318 | 242 | 110 | ||||
Income (Loss) from Discontinued Operations, net of Income Taxes | 9 | 9 | (322) | ||||||||
Net Income (Loss) | $ 130 | $ 91 | $ 53 | $ 53 | $ 35 | $ 79 | $ 53 | $ 75 | 327 | 242 | (212) |
Comprehensive Income (Loss) | $ 337 | $ 230 | $ (198) | ||||||||
Earnings Per Share | |||||||||||
Basic earnings per share of common stock from continuing operations | $ 1.25 | $ 0.96 | $ 0.45 | ||||||||
Basic earnings (loss) per share of common stock from discontinued operations | 0.04 | (1.31) | |||||||||
Basic earnings (loss) per share of common stock | 1.29 | 0.96 | (0.86) | ||||||||
Diluted earnings per share of common stock from continuing operations | 1.25 | 0.96 | 0.45 | ||||||||
Diluted earnings (loss) per share of common stock from discontinued operations | 0.04 | (1.31) | |||||||||
Diluted earnings (loss) per share of common stock | $ 1.29 | $ 0.96 | $ (0.86) | ||||||||
Parent Company [Member] | |||||||||||
Condensed Income Statements, Captions [Line Items] | |||||||||||
Operating Revenue | $ 0 | $ 0 | $ 0 | ||||||||
Operating Expenses | |||||||||||
Other operation and maintenance | 20 | 31 | 1 | ||||||||
Total operating expenses | 20 | 31 | 1 | ||||||||
Operating Income (Loss) | (20) | (31) | (1) | ||||||||
Other Income (Expenses) | |||||||||||
Interest expense | (47) | (43) | (42) | ||||||||
Income from equity investments | 312 | 291 | 204 | ||||||||
Other income | 15 | ||||||||||
Total Other Income (Expenses) | 280 | 248 | 162 | ||||||||
Income from Continuing Operations Before Income Tax | 260 | 217 | 161 | ||||||||
Income Tax Expense Related to Continuing Operations | (58) | (25) | 51 | ||||||||
Net Income from Continuing Operations | 318 | 242 | 110 | ||||||||
Income (Loss) from Discontinued Operations, net of Income Taxes | 9 | (322) | |||||||||
Net Income (Loss) | 327 | 242 | (212) | ||||||||
Comprehensive Income (Loss) | $ 337 | $ 230 | $ (198) | ||||||||
Earnings Per Share | |||||||||||
Basic earnings per share of common stock from continuing operations | $ 1.25 | $ 0.96 | $ 0.45 | ||||||||
Basic earnings (loss) per share of common stock from discontinued operations | 0.04 | (1.31) | |||||||||
Basic earnings (loss) per share of common stock | 1.29 | 0.96 | (0.86) | ||||||||
Diluted earnings per share of common stock from continuing operations | 1.25 | 0.96 | 0.45 | ||||||||
Diluted earnings (loss) per share of common stock from discontinued operations | 0.04 | (1.31) | |||||||||
Diluted earnings (loss) per share of common stock | $ 1.29 | $ 0.96 | $ (0.86) |
Schedule I - Condensed Finan130
Schedule I - Condensed Financial Information of Parent Company (Balance Sheets) (Detail) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
CURRENT ASSETS | ||||
Cash and cash equivalents | $ 25 | $ 14 | $ 23 | $ 25 |
Total Current Assets | 1,202 | 1,034 | ||
INVESTMENTS AND OTHER ASSETS | ||||
Goodwill | 1,406 | 1,407 | ||
Other | 129 | 121 | ||
TOTAL ASSETS | 16,326 | 15,589 | 14,778 | |
CURRENT LIABILITIES | ||||
Short-term debt | 1,063 | 729 | ||
Current portion of long-term debt | 294 | 366 | ||
Total Current Liabilities | 2,308 | 2,056 | ||
DEFERRED CREDITS | ||||
Long-term debt | $ 4,656 | $ 4,397 | ||
COMMITMENTS AND CONTINGENCIES (NOTE 4) | ||||
PREFERRED STOCK | ||||
Series A preferred stock, $.01 par value, 18,000 shares authorized, 18,000 and 12,600 shares outstanding, respectively | $ 183 | $ 129 | ||
EQUITY | ||||
Common stock, $.01 par value - 400,000,000 shares authorized, 254,289,261 and 252,728,684 shares outstanding, respectively | 3 | 3 | ||
Premium on stock and other capital contributions | 3,829 | 3,800 | ||
Accumulated other comprehensive loss | (36) | (46) | $ (34) | (48) |
Retained earnings | 617 | 565 | ||
TOTAL LIABILITIES AND EQUITY | 16,326 | 15,589 | ||
Parent Company [Member] | ||||
CURRENT ASSETS | ||||
Cash and cash equivalents | 65 | $ 262 | ||
Prepayments of income taxes | 171 | 152 | ||
Accounts receivable and other | 18 | 9 | ||
Total Current Assets | 189 | 226 | ||
INVESTMENTS AND OTHER ASSETS | ||||
Goodwill | 1,398 | 1,398 | ||
Investment in consolidated companies | 4,636 | 4,256 | ||
Other | 127 | 82 | ||
Total Investments and Other Assets | 6,161 | 5,736 | ||
TOTAL ASSETS | 6,350 | 5,962 | ||
CURRENT LIABILITIES | ||||
Short-term debt | 784 | 287 | ||
Current portion of long-term debt | 190 | 250 | ||
Interest and taxes accrued | 10 | 9 | ||
Accounts payable due to associated companies | 8 | 13 | ||
Total Current Liabilities | 992 | 559 | ||
DEFERRED CREDITS | ||||
Notes payable due to subsidiary companies | 498 | 494 | ||
Liabilities and accrued interest related to uncertain tax positions | 4 | |||
Total Deferred Credits | 498 | 498 | ||
Long-term debt | $ 264 | $ 454 | ||
COMMITMENTS AND CONTINGENCIES (NOTE 4) | ||||
PREFERRED STOCK | ||||
Series A preferred stock, $.01 par value, 18,000 shares authorized, 18,000 and 12,600 shares outstanding, respectively | $ 183 | $ 129 | ||
EQUITY | ||||
Common stock, $.01 par value - 400,000,000 shares authorized, 254,289,261 and 252,728,684 shares outstanding, respectively | 3 | 3 | ||
Premium on stock and other capital contributions | 3,829 | 3,800 | ||
Accumulated other comprehensive loss | (36) | (46) | ||
Retained earnings | 617 | 565 | ||
Total Equity | 4,413 | 4,322 | ||
TOTAL LIABILITIES AND EQUITY | $ 6,350 | $ 5,962 |
Schedule I - Condensed Finan131
Schedule I - Condensed Financial Information of Parent Company (Balance Sheets) (Parenthetical) (Detail) - $ / shares | Dec. 31, 2015 | Dec. 31, 2014 | Apr. 29, 2014 |
Condensed Balance Sheet Statements, Captions [Line Items] | |||
Series A preferred stock, par value | $ 0.01 | $ 0.01 | |
Series A preferred stock, shares authorized | 18,000 | 18,000 | |
Series A preferred stock, shares outstanding | 18,000 | 12,600 | |
Common stock, par value | $ 0.01 | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 400,000,000 | 400,000,000 | |
Common stock, shares outstanding | 254,289,261 | 252,728,684 | |
Parent Company [Member] | |||
Condensed Balance Sheet Statements, Captions [Line Items] | |||
Series A preferred stock, par value | $ 0.01 | $ 0.01 | |
Series A preferred stock, shares authorized | 18,000 | 18,000 | |
Series A preferred stock, shares outstanding | 18,000 | 12,600 | |
Common stock, par value | $ 0.01 | $ 0.01 | |
Common stock, shares authorized | 400,000,000 | 400,000,000 | |
Common stock, shares outstanding | 254,289,261 | 252,728,684 |
Schedule I - Condensed Finan132
Schedule I - Condensed Financial Information of Parent Company (Statements of Cash Flows) (Detail) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
OPERATING ACTIVITIES | |||||||||||
Net Income (Loss) | $ 130 | $ 91 | $ 53 | $ 53 | $ 35 | $ 79 | $ 53 | $ 75 | $ 327 | $ 242 | $ (212) |
(Income) loss from discontinued operations, net of income taxes | (9) | (9) | 322 | ||||||||
Adjustments to reconcile net income to net cash from operating activities: | |||||||||||
Deferred income taxes | 122 | 302 | 458 | ||||||||
Increase in fair value of preferred stock derivative | $ (15) | (15) | |||||||||
Other | (2) | (6) | (13) | ||||||||
Changes in: | |||||||||||
Other assets and liabilities | 8 | 10 | 9 | ||||||||
Net Cash From (Used By) Operating Activities | 939 | 854 | 497 | ||||||||
FINANCING ACTIVITIES | |||||||||||
Dividends paid on common stock | (275) | (272) | (270) | ||||||||
Common stock issued for the Direct Stock Purchase and Dividend Reinvestment Plan and employee-related compensation | 18 | 34 | 50 | ||||||||
Issuances of common stock | 324 | ||||||||||
Issuances of Series A preferred stock | 54 | 126 | |||||||||
Reacquisitions of long-term debt | (420) | (334) | (558) | ||||||||
Issuances (repayments) of short-term debt, net | 34 | 164 | (200) | ||||||||
Borrowings under term loans | 300 | 250 | |||||||||
Repayments of term loans | (100) | (450) | |||||||||
Costs of issuances | (7) | (10) | (23) | ||||||||
Net Cash From (Used By) Financing Activities | 233 | 363 | (88) | ||||||||
Net Increase (Decrease) In Cash and Cash Equivalents | 11 | (9) | (2) | ||||||||
Cash and Cash Equivalents at Beginning of Year | 14 | $ 23 | 14 | 23 | 25 | ||||||
CASH AND CASH EQUIVALENTS AT END OF YEAR | $ 25 | 14 | 25 | 14 | 23 | ||||||
Parent Company [Member] | |||||||||||
OPERATING ACTIVITIES | |||||||||||
Net Income (Loss) | 327 | 242 | (212) | ||||||||
(Income) loss from discontinued operations, net of income taxes | (9) | 322 | |||||||||
Adjustments to reconcile net income to net cash from operating activities: | |||||||||||
Distributions from related parties less than earnings | (74) | (149) | (127) | ||||||||
Deferred income taxes | (33) | (5) | (7) | ||||||||
Increase in fair value of preferred stock derivative | (15) | ||||||||||
Other | 13 | 18 | |||||||||
Changes in: | |||||||||||
Prepaid and other | 6 | 13 | 2 | ||||||||
Accounts payable | (1) | 1 | 6 | ||||||||
Interest and taxes | (23) | (141) | |||||||||
Other assets and liabilities | (22) | 1 | 3 | ||||||||
Net Cash From (Used By) Operating Activities | 169 | 121 | (154) | ||||||||
FINANCING ACTIVITIES | |||||||||||
Dividends paid on common stock | (275) | (272) | (270) | ||||||||
Common stock issued for the Direct Stock Purchase and Dividend Reinvestment Plan and employee-related compensation | 18 | 34 | 50 | ||||||||
Issuances of common stock | 324 | ||||||||||
Issuances of Series A preferred stock | 54 | 126 | |||||||||
Capital contributions to subsidiaries, net | (282) | (210) | (250) | ||||||||
Increase in notes payable due to associated companies | 4 | 3 | 491 | ||||||||
Reacquisitions of long-term debt | (250) | ||||||||||
Issuances (repayments) of short-term debt, net | 197 | 263 | (240) | ||||||||
Borrowings under term loans | 300 | 250 | |||||||||
Repayments of term loans | (450) | ||||||||||
Costs of issuances | (13) | ||||||||||
Net Cash From (Used By) Financing Activities | (234) | (56) | (108) | ||||||||
Net Increase (Decrease) In Cash and Cash Equivalents | (65) | 65 | (262) | ||||||||
Cash and Cash Equivalents at Beginning of Year | $ 65 | $ 65 | $ 262 | ||||||||
CASH AND CASH EQUIVALENTS AT END OF YEAR | $ 65 | $ 65 |
Schedule I - Condensed Finan133
Schedule I - Condensed Financial Information of Parent Company - Additional Information (Detail) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Condensed Financial Statements, Captions [Line Items] | ||
Ownership percentage of significant subsidiaries | 100.00% | |
Ratio of equity to total capitalization | 30.00% | |
Retained earnings | $ 617 | $ 565 |
Restricted net assets for consolidated subsidiaries | 2,633 | |
Surety Bond [Member] | ||
Condensed Financial Statements, Captions [Line Items] | ||
Guarantee obligations amount | 56 | |
Pepco Energy Services [Member] | Performance Guarantee [Member] | ||
Condensed Financial Statements, Captions [Line Items] | ||
Guarantee obligations amount | 269 | |
Pepco Energy Services [Member] | Surety Bond [Member] | ||
Condensed Financial Statements, Captions [Line Items] | ||
Guarantee obligations amount | 177 | |
Potomac Capital Investment Corporation (PCI) [Member] | ||
Condensed Financial Statements, Captions [Line Items] | ||
Guarantee obligations amount | $ 725 |
Schedule I - Condensed Finan134
Schedule I - Condensed Financial Information of Parent Company - Presentation of Debt Issuance Costs (Detail) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Debt Issuance Costs [Line Items] | ||
Other (within investments and other assets) | $ 129 | $ 121 |
Long-term debt | 4,656 | 4,397 |
Parent Company [Member] | ||
Debt Issuance Costs [Line Items] | ||
Other (within investments and other assets) | 127 | 82 |
Long-term debt | $ 264 | 454 |
As Filed [Member] | ||
Debt Issuance Costs [Line Items] | ||
Other (within investments and other assets) | 166 | |
Long-term debt | 4,441 | |
As Filed [Member] | Parent Company [Member] | ||
Debt Issuance Costs [Line Items] | ||
Other (within investments and other assets) | 84 | |
Long-term debt | 456 | |
Scenario, Adjustment [Member] | ||
Debt Issuance Costs [Line Items] | ||
Other (within investments and other assets) | (45) | |
Long-term debt | (44) | |
Scenario, Adjustment [Member] | Parent Company [Member] | ||
Debt Issuance Costs [Line Items] | ||
Other (within investments and other assets) | (2) | |
Long-term debt | $ (2) |
Schedule I - Condensed Finan135
Schedule I - Condensed Financial Information of Parent Company - Investment in Consolidated Companies (Detail) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Schedule of Equity Method Investments [Line Items] | ||
Total investment in consolidated companies | $ 4,636 | $ 4,256 |
Conectiv, LLC [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Total investment in consolidated companies | 2,198 | 1,984 |
Potomac Electric Power Co [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Total investment in consolidated companies | 2,240 | 2,087 |
Potomac Capital Investment Corporation (PCI) [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Total investment in consolidated companies | 40 | 30 |
Pepco Energy Services [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Total investment in consolidated companies | 155 | 153 |
PHI Service Company [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Total investment in consolidated companies | $ 3 | $ 2 |
Schedule I - Condensed Finan136
Schedule I - Condensed Financial Information of Parent Company - Related Party Transactions (Detail) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Related Party Transaction [Line Items] | ||
(Payable to) Receivable from Related Party, Total | $ (8) | $ (13) |
Money Pool Balance (included in cash and cash equivalents) | 65 | |
Conectiv Communications, Inc. [Member] | ||
Related Party Transaction [Line Items] | ||
(Payable to) Receivable from Related Party, Total | (4) | (4) |
PHI Service Company [Member] | ||
Related Party Transaction [Line Items] | ||
(Payable to) Receivable from Related Party, Total | (4) | (10) |
Other [Member] | ||
Related Party Transaction [Line Items] | ||
(Payable to) Receivable from Related Party, Total | 1 | |
Potomac Capital Investment Corporation (PCI) [Member] | ||
Related Party Transaction [Line Items] | ||
Payable to Related Party (non-current) | $ (498) | $ (494) |
Schedule II - Valuation and Qua
Schedule II - Valuation and Qualifying Accounts (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Valuation and Qualifying Accounts Disclosure [Line Items] | |||
Balance at Beginning of Period | $ 40 | $ 38 | $ 34 |
Charged to Costs and Expenses | 59 | 46 | 37 |
Charged to Other Accounts | 5 | 9 | 5 |
Deductions | (48) | (53) | (38) |
Balance at End of Period | 56 | 40 | 38 |
Potomac Electric Power Co [Member] | |||
Valuation and Qualifying Accounts Disclosure [Line Items] | |||
Balance at Beginning of Period | 16 | 16 | 13 |
Charged to Costs and Expenses | 20 | 17 | 15 |
Charged to Other Accounts | 1 | 2 | 1 |
Deductions | (20) | (19) | (13) |
Balance at End of Period | 17 | 16 | 16 |
Delmarva Power & Light Co/De [Member] | |||
Valuation and Qualifying Accounts Disclosure [Line Items] | |||
Balance at Beginning of Period | 11 | 12 | 9 |
Charged to Costs and Expenses | 20 | 13 | 11 |
Charged to Other Accounts | 2 | 4 | 1 |
Deductions | (16) | (18) | (9) |
Balance at End of Period | 17 | 11 | 12 |
Atlantic City Electric Co [Member] | |||
Valuation and Qualifying Accounts Disclosure [Line Items] | |||
Balance at Beginning of Period | 9 | 10 | 11 |
Charged to Costs and Expenses | 18 | 12 | 11 |
Charged to Other Accounts | 2 | 3 | 3 |
Deductions | (12) | (16) | (15) |
Balance at End of Period | $ 17 | $ 9 | $ 10 |