Document and Entity Information
Document and Entity Information | 12 Months Ended |
Dec. 31, 2016USD ($)shares | |
Entity Registrant Name | DPL INC |
Entity Central Index Key | 787,250 |
Document Type | 10-K |
Document Period End Date | Dec. 31, 2016 |
Amendment Flag | false |
Current Fiscal Year End Date | --12-31 |
Entity Current Reporting Status | Yes |
Entity Filer Category | Non-accelerated Filer |
Entity Common Stock, Shares Outstanding | shares | 1 |
Document Fiscal Year Focus | 2,016 |
Document Fiscal Period Focus | FY |
Entity Voluntary Filers | Yes |
Entity Well-known Seasoned Issuer | No |
Entity Public Float | $ | $ 0 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Entity Registrant Name | DAYTON POWER & LIGHT CO |
Entity Central Index Key | 27,430 |
Document Type | 10-K |
Document Period End Date | Dec. 31, 2016 |
Amendment Flag | false |
Current Fiscal Year End Date | --12-31 |
Entity Current Reporting Status | Yes |
Entity Filer Category | Non-accelerated Filer |
Entity Common Stock, Shares Outstanding | shares | 41,172,173 |
Document Fiscal Year Focus | 2,016 |
Document Fiscal Period Focus | FY |
Entity Voluntary Filers | Yes |
Entity Well-known Seasoned Issuer | No |
Entity Public Float | $ | $ 0 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Revenues | $ 1,427.3 | $ 1,612.8 | $ 1,716.5 |
Cost of revenues: | |||
Fuel | 268.8 | 259.8 | 304.5 |
Purchased power | 417.4 | 562.6 | 587.9 |
Total cost of revenues | 686.2 | 822.4 | 892.4 |
Gross margin | 741.1 | 790.4 | 824.1 |
Operating expenses: | |||
Operation and maintenance | 348.1 | 361.3 | 362.4 |
Depreciation and amortization | 132.3 | 134.6 | 135.6 |
General taxes | 85.7 | 87 | 87.8 |
Goodwill impairment (Note 7) | 0 | 317 | 0 |
Fixed-asset impairment (Note 15) | 859 | 0 | 11.5 |
Gain (Loss) on Sale of Assets and Asset Impairment Charges, excluding Discontinued Operations | 0.1 | ||
Other | (49.2) | 0.4 | (3.9) |
Total operating expenses | 1,425 | 900.3 | 593.4 |
Operating income / (loss) | (683.9) | (109.9) | 230.7 |
Other income / (expense), net | |||
Investment income | 0.4 | 0.2 | 0.9 |
Interest expense | (106.1) | (118.3) | (126.6) |
Charge for early redemption of debt | (3.1) | (2.1) | (30.9) |
Other deductions | (0.6) | (1.3) | (1.5) |
Other expense, net | (109.4) | (121.5) | (158.1) |
Income / (loss) from continuing operations before income tax | (793.3) | (231.4) | 72.6 |
Income tax expense / (benefit) from continuing operations | (278.8) | 20 | 15.4 |
Net income / (loss) from continuing operations | (514.5) | (251.4) | 57.2 |
Income / (loss) from discontinued operations | (0.7) | 11.4 | (129.2) |
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax | 49.2 | 0 | 0 |
Income tax expense / (benefit) | 19.2 | (1) | 2.6 |
Net income / (loss) from discontinued operations | 29.3 | 12.4 | (131.8) |
Net loss | (485.2) | (239) | (74.6) |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Revenues | 1,365.9 | 1,552.3 | 1,668.3 |
Cost of revenues: | |||
Fuel | 248.9 | 244.7 | 314.9 |
Purchased power | 414.1 | 555.7 | 582.4 |
Total cost of revenues | 663 | 800.4 | 897.3 |
Gross margin | 702.9 | 751.9 | 771 |
Operating expenses: | |||
Operation and maintenance | 343.2 | 350.5 | 355.2 |
Depreciation and amortization | 120.3 | 138.2 | 144.8 |
General taxes | 83.8 | 85 | 85.7 |
Gain (Loss) on Contract Termination | (27.7) | 0 | 0 |
Fixed-asset impairment (Note 15) | 1,353.5 | 0 | 0 |
Gain (Loss) on Sale of Assets and Asset Impairment Charges, excluding Discontinued Operations | 0.1 | ||
Other | 0 | 0.4 | (3.5) |
Total operating expenses | 1,873 | 574.1 | 582.2 |
Operating income / (loss) | (1,170.1) | 177.8 | 188.8 |
Other income / (expense), net | |||
Investment income | 0.4 | 0.3 | 0.9 |
Interest expense | (24.5) | (30.9) | (33.9) |
Charge for early redemption of debt | (0.5) | (5) | 0 |
Other deductions | (0.4) | (0.7) | (1.1) |
Other expense, net | (25) | (36.3) | (34.1) |
Income / (loss) from continuing operations before income tax | (1,195.1) | 141.5 | 154.7 |
Income tax expense / (benefit) from continuing operations | (422.4) | 35.1 | 39.7 |
Dividends on preferred stock | 0.7 | 0.9 | 0.9 |
Income / (loss) attributable to common stock | (773.4) | 105.5 | 114.1 |
Net loss | $ (772.7) | $ 106.4 | $ 115 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income/(Loss) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Net loss | $ (485.2) | $ (239) | $ (74.6) |
Available-for-sale securities activity: | |||
Change in fair value of available-for-sale securities, net of income tax benefit/(expense) | 0.2 | (0.1) | (0.3) |
Reclassification to earnings of available-for-sale securities, net of income tax expense/(benefit) | 0 | 0 | 0.2 |
Total change in fair value of available-for-sale securities | 0.2 | (0.1) | (0.1) |
Derivative activity: | |||
Change in derivative fair value, net of income tax benefit/(expense) | 16.1 | 18.2 | (19) |
Reclassification of earnings, net of income tax benefit/(expense) | (29.7) | (10) | 16.9 |
Total change in fair value of derivatives | (13.6) | 8.2 | (2.1) |
Pension and postretirement activity: | |||
Prior service cost for the period, net of income tax benefit/(expense) | 0 | 0 | (2.2) |
Net loss for the period, net of income tax benefit/(expense) | (4.7) | 1.6 | (12.7) |
Reclassification to earnings, net of income tax benefit/(expense) | 1 | 0.2 | 0 |
Total change in unfunded pension obligation | (3.7) | 1.8 | (14.9) |
Other comprehensive income / (loss) | (17.1) | 9.9 | (17.1) |
Net comprehensive income / (loss) | (502.3) | (229.1) | (91.7) |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Net loss | (772.7) | 106.4 | 115 |
Available-for-sale securities activity: | |||
Change in fair value of available-for-sale securities, net of income tax benefit/(expense) | 0.2 | (0.2) | (0.3) |
Reclassification to earnings of available-for-sale securities, net of income tax expense/(benefit) | 0 | 0 | 0.2 |
Total change in fair value of available-for-sale securities | 0.2 | (0.2) | (0.1) |
Derivative activity: | |||
Change in derivative fair value, net of income tax benefit/(expense) | 16.1 | 18.2 | (18.8) |
Reclassification of earnings, net of income tax benefit/(expense) | (30) | (9.8) | 15.4 |
Total change in fair value of derivatives | (13.9) | 8.4 | (3.4) |
Pension and postretirement activity: | |||
Prior service cost for the period, net of income tax benefit/(expense) | (0.1) | 0 | (2.3) |
Net loss for the period, net of income tax benefit/(expense) | (5.9) | 1.7 | (12.5) |
Reclassification to earnings, net of income tax benefit/(expense) | 5.9 | 3.7 | 2.7 |
Total change in unfunded pension obligation | (0.1) | 5.4 | (12.1) |
Other comprehensive income / (loss) | (13.8) | 13.6 | (15.6) |
Net comprehensive income / (loss) | $ (786.5) | $ 120 | $ 99.4 |
Consolidated Statements of Com4
Consolidated Statements of Comprehensive Income/(Loss) (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Income tax (expense)/benefit on unrealized gains (losses) related to available-for-sale securities | $ (0.1) | $ 0.1 | $ 0.2 |
Other Comprehensive Income (Loss), Reclassification Adjustment for Sale of Securities Included in Net Income, Tax | 0 | 0 | (0.2) |
Income tax (expense)/benefit on unrealized gains (losses) related to derivative activity | (8.8) | (10.3) | 10.3 |
Income tax (expense)/benefit on reclassification of earnings related to derivative activity | 16.7 | 5.4 | (9.5) |
Income tax (expense)/benefit on prior service cost related to pension and postretirement activity | 0 | 0 | 1.3 |
Income tax (expense)/benefit on net loss related to pension and postretirement activity | 2.4 | (1.2) | 7.1 |
Income tax (expense)/benefit on reclassification of earnings related to pension and postretirement activity | (0.6) | (0.2) | 0 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Income tax (expense)/benefit on unrealized gains (losses) related to available-for-sale securities | (0.1) | 0.1 | 0.2 |
Other Comprehensive Income (Loss), Reclassification Adjustment for Sale of Securities Included in Net Income, Tax | 0 | 0 | (0.2) |
Income tax (expense)/benefit on unrealized gains (losses) related to derivative activity | (8.7) | (10.3) | 10.5 |
Income tax (expense)/benefit on reclassification of earnings related to derivative activity | 16.4 | 5.6 | (11.5) |
Income tax (expense)/benefit on prior service cost related to pension and postretirement activity | 0 | 0 | 1.3 |
Income tax (expense)/benefit on net loss related to pension and postretirement activity | 1.1 | (1) | 7.2 |
Income tax (expense)/benefit on reclassification of earnings related to pension and postretirement activity | $ (1.8) | $ (1.9) | $ (1.5) |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Current assets: | ||
Cash and cash equivalents | $ 54.6 | $ 32.4 |
Restricted cash | 29 | 92.7 |
Accounts receivable, net | 135.1 | 120.9 |
Inventories | 77.2 | 109.1 |
Taxes applicable to subsequent years | 81 | 81.2 |
Regulatory assets, current | 0.1 | 14.4 |
Other prepayments and current assets | 31.8 | 44.5 |
Assets held for sale - current | 0 | 62.2 |
Total current assets | 408.8 | 557.4 |
Property, plant and equipment: | ||
Property, plant and equipment | 1,985.6 | 2,850.7 |
Less: Accumulated depreciation and amortization | (334.8) | (397) |
Property, plant and equipment, net of depreciation | 1,650.8 | 2,453.7 |
Construction work in process | 116.4 | 83.5 |
Total net property, plant and equipment | 1,767.2 | 2,537.2 |
Other non-current assets: | ||
Regulatory assets, non-current | 203.9 | 179.9 |
Intangible assets, net of amortization | 22.7 | 29.5 |
Other deferred assets | 16.6 | 20.7 |
Total other non-current assets | 243.2 | 230.1 |
Total Assets | 2,419.2 | 3,324.7 |
LIABILITIES AND SHAREHOLDER'S EQUITY | ||
Current portion - long-term debt | 29.7 | 572.8 |
Accounts payable | 113.9 | 97.5 |
Accrued taxes | 185.1 | 142.4 |
Accrued interest | 17.7 | 21.4 |
Customer security deposits | 15.2 | 15.2 |
Regulatory liabilities, current | 33.7 | 24.4 |
Insurance and claims costs | 5.4 | 5.9 |
Other current liabilities | 50.2 | 54.5 |
Deposit received on sale of DPLER | 0 | 75.5 |
Liabilities held for sale - current | 0 | 1.6 |
Total current liabilities | 450.9 | 1,011.2 |
Non-current liabilities: | ||
Long-term debt | 1,828.7 | 1,420.5 |
Deferred taxes | 252.4 | 568.7 |
Taxes payable | 84.6 | 84.1 |
Regulatory liabilities, non-current | 130.4 | 127 |
Pension, retiree and other benefits | 101.6 | 87.1 |
Asset Retirement Obligations, Noncurrent | 138.8 | 65.9 |
Other deferred credits | 19.4 | 22.4 |
Total non-current liabilities | 2,555.9 | 2,375.7 |
Redeemable preferred stock of subsidiary | 0 | 18.4 |
Commitments and contingencies | ||
Common shareholder's equity: | ||
Common stock | 0 | 0 |
Other paid-in capital | 2,233 | 2,237.7 |
Accumulated other comprehensive income/(loss) | 0.3 | 17.4 |
Retained earnings / (deficit) | (2,820.9) | (2,335.7) |
Total common shareholder's equity | (587.6) | (80.6) |
Total Liabilities and Shareholder's Equity | 2,419.2 | 3,324.7 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Current assets: | ||
Cash and cash equivalents | 1.6 | 5.4 |
Restricted cash | 29 | 44.8 |
Accounts receivable, net | 134.6 | 119.5 |
Inventories | 75.8 | 108 |
Taxes applicable to subsequent years | 79.2 | 79.2 |
Regulatory assets, current | 0.1 | 14.4 |
Other prepayments and current assets | 32.4 | 46.3 |
Total current assets | 352.7 | 417.6 |
Property, plant and equipment: | ||
Property, plant and equipment | 2,398.6 | 5,172.3 |
Less: Accumulated depreciation and amortization | (1,047.9) | (2,534.8) |
Property, plant and equipment, net of depreciation | 1,350.7 | 2,637.5 |
Construction work in process | 89.9 | 76.5 |
Total net property, plant and equipment | 1,440.6 | 2,714 |
Other non-current assets: | ||
Regulatory assets, non-current | 203.9 | 179.9 |
Goodwill | 0 | |
Intangible assets, net of amortization | 23 | 29.7 |
Other deferred assets | 14.9 | 18.4 |
Total other non-current assets | 241.8 | 228 |
Total Assets | 2,035.1 | 3,359.6 |
LIABILITIES AND SHAREHOLDER'S EQUITY | ||
Current portion - long-term debt | 4.7 | 443.1 |
Short-term debt | 5 | 35 |
Accounts payable | 110.5 | 94.1 |
Accrued taxes | 75.7 | 86.2 |
Accrued interest | 2.1 | 4.1 |
Customer security deposits | 15.2 | 15.1 |
Regulatory liabilities, current | 33.7 | 24.4 |
Other current liabilities | 48.3 | 51 |
Advance on contract termination | 0 | 27.7 |
Total current liabilities | 295.2 | 780.7 |
Non-current liabilities: | ||
Long-term debt | 744.7 | 313.6 |
Deferred taxes | 146.3 | 631.2 |
Taxes payable | 84.1 | 82.1 |
Regulatory liabilities, non-current | 130.4 | 127 |
Pension, retiree and other benefits | 101.6 | 87.1 |
Unamortized investment tax credit | 17.7 | 20 |
Asset Retirement Obligations, Noncurrent | 135.2 | 62.1 |
Other deferred credits | 17.6 | 20.2 |
Total non-current liabilities | 1,377.6 | 1,343.3 |
Redeemable preferred stock of subsidiary | 0 | 22.9 |
Commitments and contingencies | ||
Common shareholder's equity: | ||
Common stock | 0.4 | 0.4 |
Other paid-in capital | 810.7 | 803.7 |
Accumulated other comprehensive income/(loss) | (42.5) | (28.7) |
Retained earnings / (deficit) | (406.3) | 437.3 |
Total common shareholder's equity | 362.3 | 1,212.7 |
Total Liabilities and Shareholder's Equity | $ 2,035.1 | $ 3,359.6 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Dec. 31, 2016 | Dec. 31, 2015 |
Common stock, shares authorized | 1,500 | 1,500 |
Common stock, shares outstanding | 1 | 1 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Common stock, shares authorized | 250,000,000 | 250,000,000 |
Common stock, shares outstanding | 41,172,173 | 41,172,173 |
Common stock, par value (in USD per share) | $ 0.01 | $ 0.01 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Cash flows from operating activities: | ||||
Net income (loss) | $ (485.2) | $ (239) | $ (74.6) | |
Adjustments to reconcile Net loss to Net cash from operating activities | ||||
Depreciation and amortization | 132.3 | 138.8 | 139.8 | |
Amortization of intangibles | 0 | 0 | 1.2 | |
Amortization of debt market value adjustments | 0.1 | (1.1) | 0.3 | |
Amortization of deferred financing costs | 5.6 | 5.9 | 6.3 | |
Unrealized loss (gain) on derivatives | (4.3) | 5.8 | 3 | |
Deferred income taxes | (306.2) | (17.1) | 17.7 | |
Charge for early redemption of debt | 3.1 | 2.1 | 30.9 | |
Goodwill impairment | [1] | 0 | 317 | 135.8 |
Fixed-asset impairment (Note 15) | 859 | 0 | 11.5 | |
Loss / (Gain) on asset disposal | (49.2) | 0.4 | (3.9) | |
Changes in certain assets and liabilities: | ||||
Accounts receivable | 24.2 | 43.4 | 0.5 | |
Inventories | 32 | (9) | (24.9) | |
Prepaid taxes | 0.2 | (1.3) | (0.9) | |
Taxes applicable to subsequent years | 0.2 | (3.4) | (7.1) | |
Deferred regulatory costs, net | 4.1 | 21.8 | 5.4 | |
Accounts payable | 16.5 | (5.1) | 32.1 | |
Accrued taxes payable | 45.1 | 43.8 | 20.7 | |
Accrued interest payable | (3.7) | (5.7) | (1.3) | |
Other current and deferred liabilities | (4) | (10.4) | (40.6) | |
Pension, retiree and other benefits | 8.6 | (0.7) | 19.1 | |
Unamortized investment tax credit | (0.4) | (0.5) | (0.5) | |
Insurance and claims costs | (0.5) | (0.5) | (0.2) | |
Other | (10.4) | 23.3 | (26.2) | |
Net cash provided by operating activities | 267.1 | 308.5 | 244.1 | |
Cash flows from investing activities: | ||||
Capital expenditures | (148.5) | (137.2) | (118.1) | |
Proceeds from sale of property | 75.5 | 1.3 | 10.7 | |
Insurance proceeds | 6.3 | 0 | 0.3 | |
Purchase of renewable energy credits | (0.4) | (0.8) | (3.5) | |
Increase in restricted cash | (11.8) | (0.4) | (3.3) | |
Other investing activities, net | 1.1 | 0.4 | 1.3 | |
Net cash used in investing activities | (77.8) | (136.7) | (112.6) | |
Cash flows from financing activities: | ||||
Deferred financing costs | (8.6) | (6.9) | (3.6) | |
Preferred Stock, Redemption Amount | (23.5) | 0 | 0 | |
Retirement of debt | (577.8) | (474.5) | (335) | |
Premium paid for early redemption of debt | 0 | 0 | (29.1) | |
Issuance of long-term debt | 442.8 | 325 | 200 | |
Borrowings from revolving credit facilities | 15 | 80 | 190 | |
Repayment of borrowings from revolving credit facilities | (15) | (80) | (190) | |
Net cash from financing activities | (167.1) | (156.4) | (167.7) | |
Cash and cash equivalents: | ||||
Net increase / (decrease) in cash | 22.2 | 15.4 | (36.2) | |
Balance at beginning of period | 32.4 | 17 | ||
Cash and cash equivalents at end of period | 54.6 | 32.4 | 17 | |
Supplemental cash flow information: | ||||
Interest paid, net of amounts capitalized | 103.8 | 111.6 | 117.3 | |
Income taxes paid / (refunded), net | 0.3 | 0.8 | 0.7 | |
Non-cash financing and investing activities: | ||||
Accruals for capital expenditures | 16.2 | 18.6 | 16.3 | |
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Cash flows from operating activities: | ||||
Net income (loss) | (772.7) | 106.4 | 115 | |
Adjustments to reconcile Net loss to Net cash from operating activities | ||||
Depreciation and amortization | 120.3 | 138.2 | 144.8 | |
Amortization of deferred financing costs | 2.9 | 2.9 | 3.1 | |
Unrealized loss (gain) on derivatives | (4.2) | 5.7 | 2.1 | |
Deferred income taxes | (477.5) | (19.2) | 7.5 | |
Charge for early redemption of debt | 0.5 | 5 | 0 | |
Goodwill impairment | 317 | |||
Fixed-asset impairment (Note 15) | 1,353.5 | 0 | 0 | |
Loss / (Gain) on asset disposal | 0 | 0.4 | (3.5) | |
Changes in certain assets and liabilities: | ||||
Accounts receivable | (9.7) | 28.7 | (7.1) | |
Inventories | 32.2 | (9.1) | (24.6) | |
Prepaid taxes | 2.7 | (1.3) | (1.1) | |
Taxes applicable to subsequent years | 0 | (3.7) | (6.9) | |
Deferred regulatory costs, net | 4.1 | 21.8 | 5.4 | |
Accounts payable | 16 | (5.8) | 32.4 | |
Accrued taxes payable | (10.5) | 7.3 | 9 | |
Accrued interest payable | (2) | (5.7) | 0.1 | |
Other current and deferred liabilities | (1.8) | (9.3) | (18.1) | |
Pension, retiree and other benefits | 8.6 | (0.7) | 19.1 | |
Unamortized investment tax credit | (2.3) | (2.4) | (2.5) | |
Other | 5.2 | 2.5 | (23) | |
Net cash provided by operating activities | 264.8 | 256.7 | 251.7 | |
Cash flows from investing activities: | ||||
Capital expenditures | (128.3) | (127) | (114.2) | |
Proceeds from sale of property | 0 | 0 | 10.7 | |
Insurance proceeds | 6.1 | 5.2 | 0.9 | |
Purchase of renewable energy credits | (0.4) | (0.8) | (3.5) | |
Increase in restricted cash | (11.9) | (0.3) | (3.7) | |
Other investing activities, net | 1.1 | 0.4 | 1.3 | |
Net cash used in investing activities | (133.4) | (122.5) | (108.5) | |
Cash flows from financing activities: | ||||
Dividends paid on preferred stock | (0.7) | (0.9) | (0.9) | |
Deferred financing costs | (8.5) | (3.9) | (0.7) | |
Preferred Stock, Redemption Amount | (23.5) | 0 | 0 | |
Retirement of debt | (445.3) | (314.4) | (0.1) | |
Issuance of long-term debt | 442.8 | 200 | 0 | |
Borrowings from revolving credit facilities | 0 | 50 | 0 | |
Repayment of borrowings from revolving credit facilities | 0 | (50) | 0 | |
Dividends paid on common stock to parent | (70) | (50) | (159) | |
Borrowings from related party | 10 | 35 | 15 | |
Repayment of borrowings from related party | (40) | 0 | (15) | |
Net cash from financing activities | (135.2) | (134.2) | (160.7) | |
Cash and cash equivalents: | ||||
Net increase / (decrease) in cash | (3.8) | 0 | (17.5) | |
Balance at beginning of period | 5.4 | 5.4 | 22.9 | |
Cash and cash equivalents at end of period | 1.6 | 5.4 | 5.4 | |
Supplemental cash flow information: | ||||
Interest paid, net of amounts capitalized | 21.4 | 27.5 | 26.6 | |
Income taxes paid / (refunded), net | 0.3 | 0.8 | 0.7 | |
Non-cash financing and investing activities: | ||||
Accruals for capital expenditures | 14.8 | 16.9 | 16.3 | |
Subsidiary of Common Parent [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Non-cash financing and investing activities: | ||||
Equity Settlement of Related Party Payable | $ 7.5 | $ 0 | $ 0 | |
[1] | Goodwill impairment of $135.8 million in 2014 has been reclassified to Discontinued operations in the Consolidated Statement of Operations. |
Consolidated Statements of Cas8
Consolidated Statements of Cash Flows (Parenthetical) $ in Millions | 12 Months Ended | |
Dec. 31, 2014USD ($) | ||
Goodwill impairment reclassified | $ 135.8 | [1] |
Discontinued Operations [Member] | ||
Goodwill impairment reclassified | $ 135.8 | |
[1] | Goodwill impairment of $135.8 million in 2014 has been reclassified to Discontinued operations in the Consolidated Statement of Operations. |
Consolidated Statements of Shar
Consolidated Statements of Shareholders' Equity - USD ($) $ in Millions | Total | Common Stock [Member] | Other Paid-In Capital [Member] | Accumulated Other Comprehensive Income/(Loss) [Member] | Retained Earnings [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]Common Stock [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]Other Paid-In Capital [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]Accumulated Other Comprehensive Income/(Loss) [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]Retained Earnings [Member] |
Balance at Dec. 31, 2013 | $ 239.5 | $ 0 | $ 2,237 | $ 24.6 | $ (2,022.1) | $ 1,204 | $ 0.4 | $ 803.5 | $ (26.7) | $ 426.8 |
Balance (in shares) at Dec. 31, 2013 | 1 | 41,172,173 | ||||||||
Net comprehensive income/ (loss) | (91.7) | (17.1) | (74.6) | 99.4 | (15.6) | 115 | ||||
Common stock dividends | (159) | (159) | ||||||||
Preferred stock dividends | (0.9) | (0.9) | ||||||||
Other | 0.4 | 0.4 | 0 | (0.1) | (0.1) | |||||
Balance at Dec. 31, 2014 | 148.2 | $ 0 | 2,237.4 | 7.5 | (2,096.7) | 1,143.4 | $ 0.4 | 803.5 | (42.3) | 381.8 |
Balance (in shares) at Dec. 31, 2014 | 1 | 41,172,173 | ||||||||
Net comprehensive income/ (loss) | (229.1) | 9.9 | (239) | 120 | 13.6 | 106.4 | ||||
Common stock dividends | (50) | (50) | ||||||||
Preferred stock dividends | (0.9) | (0.9) | ||||||||
Other | 0.3 | 0.3 | 0 | 0.2 | 0.2 | |||||
Balance at Dec. 31, 2015 | (80.6) | $ 0 | 2,237.7 | 17.4 | (2,335.7) | 1,212.7 | $ 0.4 | 803.7 | (28.7) | 437.3 |
Balance (in shares) at Dec. 31, 2015 | 1 | 41,172,173 | ||||||||
Preferred Stock Redemption Premium | 5.1 | |||||||||
Net comprehensive income/ (loss) | (502.3) | (17.1) | (485.2) | (786.5) | (13.8) | (772.7) | ||||
Common stock dividends | (70) | (70) | ||||||||
Preferred stock dividends | (0.7) | (0.7) | ||||||||
Other | (4.7) | (4.7) | 0 | 6.8 | 7 | (0.2) | ||||
Balance at Dec. 31, 2016 | $ (587.6) | $ 0 | $ 2,233 | $ 0.3 | $ (2,820.9) | $ 362.3 | $ 0.4 | $ 810.7 | $ (42.5) | $ (406.3) |
Balance (in shares) at Dec. 31, 2016 | 1 |
Consolidated Statements of Sh10
Consolidated Statements of Shareholders' Equity (Parenthetical) - $ / shares | Dec. 31, 2016 | Dec. 31, 2015 |
Common stock, shares authorized | 1,500 | 1,500 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Common stock, par value (in USD per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 250,000,000 | 250,000,000 |
Overview and Summary of Signifi
Overview and Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2016 | |
Significant Accounting Policies [Line Items] | |
Overview and Summary of Significant Accounting Policies | Overview and Summary of Significant Accounting Policies Description of Business DPL is a diversified regional energy company organized in 1985 under the laws of Ohio. DPL has two reportable segments, the Transmission and Distribution ("T&D") segment and the Generation segment . See Note 14 – Business Segments for more information relating to reportable segments. The terms “we”, “us”, “our” and “ours” are used to refer to DPL and its subsidiaries. On November 28, 2011, DPL was acquired by AES in the Merger and DPL became a wholly-owned subsidiary of AES. Following the merger of DPL and Dolphin Subsidiary II, Inc., DPL became an indirectly wholly-owned subsidiary of AES. DP&L is a public utility incorporated in 1911 under the laws of Ohio. Beginning in 2001, Ohio law gave Ohio consumers the right to choose the electric generation supplier from whom they purchase retail generation service, however transmission and distribu tion services are still regulated. DP&L has the exclusive right to provide such service to its approximately 519,000 customers located in West Central Ohio. Additionally, DP&L procures and provides retail SSO electric service to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio and generates electricity at five coal-fired power stations. Beginning January 2016, all of the electric supply for SSO customers is competitively bid. Principal industries located in DP&L’s service territory include automotive, food processing, paper, plastic, manufacturing and defense. DP&L's sales reflect the gen eral economic conditions, seasonal weather patterns of the area and the market price of electricity. DP&L sells energy and capacity into the wholesale market. Through December 31, 2015, DP&L's generation was also used to provide electricity to its SSO customers, as it transitioned to a competitive bidding structure in 2014 and 2015, and also sold electricity to DPLER, an affiliate, to satisfy the electric requirements of DPLER's retail customers. On December 30, 2013, DP&L filed an application with the PUCO stating its plan to transfer or sell its generation assets. On July 14, 2014, DP&L announced its decision to retain DP&L’s generation assets. On September 17, 2014, the PUCO ordered that DP&L’s application as amended and updated was approved. DP&L continues to look at multiple options to effectuate the separation, including transfer into an unregulated affiliate of DPL or through a sale. DPLER was sold by DPL on January 1, 2016. DPLER sold competitive retail electric service, under contract, to residential, commercial and industrial customers. DPLER did not own any transmission or generation assets, and it purchased all of its electric energy from DP&L to meet its sales obligations. See Note 16 – Discontinued Operations for more information. DPL’s other significant subsidiaries include AES Ohio Generation, which owns and operates peaking generating facilities from which it makes wholesale sales of electricity, and MVIC, our captive insurance company that provides insurance services to us and our other subsidiaries. DPL owns all of the common stock of its subsidiaries. DPL also has a wholly-owned business trust, DPL Capital Trust II, formed for the purpose of issuing trust capital securities to investors. DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators, while its generation business is deemed competitive under Ohio law. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates, and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs. DPL and its subsidiaries employed 1,168 people at January 31, 2017 , of which 1,160 were employed by DP&L . Approximately 62% of all DPL employees are under a collective bargaining agreement which expires on October 31, 2017 . Financial Statement Presentation We prepare Consolidated Financial Statements for DPL . DPL’s Consolidated Financial Statements include the accounts of DPL and its wholly-owned subsidiaries except for DPL Capital Trust II which is not consolidated, consistent with the provisions of GAAP. DP&L’s undivided ownership interests in certain coal-fired generating stations are included in the financial statements at amortized cost, which was adjusted to fair value at the Merger date. Operating revenues and expenses are included on a pro rata basis in the corresponding lines in the Consolidated Statement of Operations. See Note 4 – Property, Plant and Equipment for more information. All material intercompany accounts and transactions are eliminated in consolidation. We have evaluated subsequent events through the date this report is issued. Certain amounts from prior periods have been reclassified to conform to the current period presentation. See “Intangibles” below for additional information. The preparation of financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the revenues and expenses of the periods reported. Actual results could differ from these estimates. Significant items subject to such estimates and judgments include: the carrying value of Property, plant and equipment; unbilled revenues; the valuation of derivative instruments; the valuation of insurance and claims liabilities; the valuation of allowances for receivables and deferred income taxes; regulatory assets and liabilities; reserves recorded for income tax exposures; litigation; contingencies; the valuation of AROs; assets and liabilities related to employee benefits; and intangibles. Valuation of Goodwill FASC 350, “Intangibles – Goodwill and Other”, requires that goodwill be tested for impairment at the reporting unit level at least annually or more frequently if impairment indicators are present. In evaluating the potential impairment of goodwill, we make estimates and assumptions about revenue, operating cash flows, capital expenditures, growth rates and discount rates based on our budgets and long term forecasts, macroeconomic projections, and current market expectations of returns on similar assets. There are inherent uncertainties related to these factors and management’s judgment in applying these factors. Generally, the fair value of a reporting unit is determined using a discounted cash flow valuation model. See Note 7 – Goodwill for information regarding the impairment of goodwill in 2015 and 2014. Revenue Recognition Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. We consider revenue realized, or realizable, and earned when persuasive evidence of an arrangement exists, the products or services have been provided to the customer, the sales price is fixed or determinable, and collection is reasonably assured. Energy sales to customers are based on the reading of their meters that occurs on a systematic basis throughout the month. We recognize the revenues on our statements of operations using an accrual method for retail and other energy sales that have not yet been billed, but where electricity has been consumed. This is termed “unbilled revenues” and is a widely recognized and accepted practice for utilities. At the end of each month, unbilled revenues are determined by the estimation of unbilled energy provided to customers since the date of the last meter reading, estimated line losses, the assignment of unbilled energy provided to customer classes and the average rate per customer class. All of the power produced at the generation stations is sold to an RTO and we in turn purchase it back from the RTO to supply our customers. The power sales and purchases within DP&L’s service territory are reported on a net hourly basis as revenues or purchased power on our Consolidated Statements of Operations. We record expenses when purchased electricity is received and when expenses are incurred, with the exception of the ineffective portion of certain power purchase contracts that are derivatives and qualify for hedge accounting. We also have certain derivative contracts that do not qualify for hedge accounting, and their unrealized gains or losses are recorded prior to the receipt of electricity. Allowance for Uncollectible Accounts We establish provisions for uncollectible accounts by using both historical average loss percentages to project future losses and by establishing specific provisions for known credit issues. Amounts are written off when reasonable collections efforts have been exhausted. Property, Plant and Equipment We record our ownership share of our undivided interest in jointly-held stations as an asset in property, plant and equipment. New property, plant and equipment additions are stated at cost. For regulated transmission and distribution property, cost includes direct labor and material, allocable overhead expenses and an allowance for funds used during construction (AFUDC). AFUDC represents the cost of borrowed funds and equity used to finance regulated construction projects. For non-regulated property, cost also includes capitalized interest. Capitalization of AFUDC and interest ceases at either project completion or at the date specified by regulators. AFUDC and capitalized interest was $2.8 million , $2.0 million and $1.5 million in the years ended December 31, 2016 , 2015 and 2014 , respectively. For unregulated generation property, cost includes direct labor and material, allocable overhead expenses and interest capitalized during construction using the provisions of GAAP relating to the accounting for capitalized interest. For substantially all depreciable property, when a unit of property is retired, the original cost of that property less any salvage value is charged to Accumulated depreciation and amortization, consistent with composite depreciation practices. Property is evaluated for impairment when events or changes in circumstances indicate that its carrying amount may not be recoverable. See Note 15 – Fixed-asset Impairment for more information. Repairs and Maintenance Costs associated with maintenance activities, primarily power station outages, are recognized at the time the work is performed. These costs, which include labor, materials and supplies, and outside services required to maintain equipment and facilities, are capitalized or expensed based on defined units of property. Depreciation Depreciation expense is calculated using the straight-line method, which allocates the cost of property over its estimated useful life. For DPL’s generation, transmission and distribution assets, straight-line depreciation is applied monthly on an average composite basis using group rates that approximated 6.1% in 2016 , 4.4% in 2015 and 5.3% in 2014 . Depreciation expense was $121.9 million , $125.9 million and $128.1 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. Regulatory Accounting As a regulated utility, we apply the provisions of FASC 980 “Regulated Operations”, which gives recognition to the ratemaking and accounting practices of the PUCO and the FERC. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory assets can also represent performance incentives permitted by the regulator. Regulatory assets have been included as allowable costs for ratemaking purposes, as authorized by the PUCO or established regulatory practices. Regulatory liabilities generally represent obligations to make refunds or future rate reductions to customers for previous over collections or the deferral of revenues collected for costs that DP&L expects to incur in the future. The deferral of costs (as regulatory assets) is appropriate only when the future recovery of such costs is probable. In assessing probability, we consider such factors as specific orders from the PUCO or FERC, regulatory precedent and the current regulatory environment. To the extent recovery of costs is no longer deemed probable, related regulatory assets would be required to be expensed in current period earnings. Our regulatory assets and liabilities have been created pursuant to a specific order of the PUCO or FERC or established regulatory practices, such as other utilities under the jurisdiction of the PUCO or FERC being granted recovery of similar costs. It is probable, but not certain, that these regulatory assets will be recoverable, subject to PUCO or FERC approval. Regulatory assets and liabilities are classified as current or non-current based on the term in which recovery is expected. See Note 3 – Regulatory Matters for more information. Inventories Inventories are carried at average cost and include coal, limestone, oil and gas used for electric generation, and materials and supplies used for utility operations. Intangibles Intangibles include software, emission allowances and renewable energy credits. Emission allowances are carried on a first-in, first-out (FIFO) basis for purchased emission allowances. Net gains or losses on the sale of excess emission allowances, representing the difference between the sales proceeds and the cost of emission allowances, are recorded as a component of our fuel costs and are reflected in Operating income when realized. Emission allowances are amortized as they are used in our operations on a FIFO basis. Renewable energy credits are carried on a weighted average cost basis and amortized as they are used or retired. Intangible assets include capitalized software of $65.1 million and $59.9 million and its corresponding amortization of $43.2 million and $35.3 million previously classified within Total net property, plant and equipment that were reclassified to Intangible assets as of December 31, 2016 and 2015 , respectively. These assets are amortized over seven years. See “ New Accounting Pronouncements ” below for additional information. A mortization expense was $7.7 million , $9.0 million and $8.6 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. The estimated amortization expense of this internal-use software is $15.3 million ( $6.1 million in 2017, $5.6 million in 2018 and $3.6 million in 2019 ). Income Taxes Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases. We establish an allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. Our tax positions are evaluated under a more likely than not recognition threshold and measurement analysis before they are recognized for financial statement reporting. Uncertain tax positions have been classified as noncurrent income tax liabilities unless expected to be paid within one year. Our policy for interest and penalties is to recognize interest and penalties as a component of the provision for income taxes in the Consolidated Statement of Operations. Income taxes payable, which are includable in allowable costs for ratemaking purposes in future years, are recorded as regulatory assets with a corresponding deferred tax liability. Investment tax credits that reduced federal income taxes in the years they arose have been deferred and are being amortized to income over the useful lives of the properties in accordance with regulatory treatment. See Note 3 – Regulatory Matters for additional information. DPL and its subsidiaries file U.S. federal income tax returns as part of the consolidated U.S. income tax return filed by AES. The consolidated tax liability is allocated to each subsidiary based on the separate return method which is specified in our tax allocation agreement and which provides a consistent, systematic and rational approach. See Note 9 – Income Taxes for additional information. Financial Instruments We classify our investments in debt and equity financial instruments of publicly traded entities into different categories: held-to-maturity and available-for-sale. Available-for-sale securities are carried at fair value and unrealized gains and losses on those securities, net of deferred income taxes, are presented as a separate component of shareholder's equity. Other-than-temporary declines in value are recognized currently in earnings. Financial instruments classified as held-to-maturity are carried at amortized cost. The cost bases for public equity security and fixed maturity investments are average cost and amortized cost, respectively. Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities DP&L collects certain excise taxes levied by state or local governments from its customers. DP&L’s excise taxes and certain other taxes are accounted for on a net basis and recorded as a reduction in revenues in the accompanying Statements of Operations. The amounts for the years ended December 31, 2016 , 2015 and 2014 , were $50.9 million , $49.9 million and $50.8 million , respectively. Cash and Cash Equivalents Cash and cash equivalents are stated at cost, which approximates fair value. All highly liquid short-term investments with original maturities of three months or less are considered cash equivalents. Restricted Cash Restricted cash includes cash which is restricted as to withdrawal or usage. The nature of the restrictions includes restrictions imposed by agreements related to deposits held as collateral. At December 31, 2015, restricted cash also includes cash received in connection with the sale of DPLER on January 1, 2016. See Note 16 – Discontinued Operations for additional information regarding the sale of DPLER. Financial Derivatives All derivatives are recognized as either assets or liabilities in the balance sheets and are measured at fair value. Changes in the fair value are recorded in earnings unless the derivative is designated as a cash flow hedge of a forecasted transaction or it qualifies for the normal purchases and sales exception. We use forward contracts to reduce our exposure to changes in energy and commodity prices and as a hedge against the risk of changes in cash flows associated with expected electricity purchases. We hold forward sales contracts that hedge against the risk of changes in cash flows associated with power sales during periods of projected generation facility availability. We use cash flow hedge accounting when the hedge or a portion of the hedge is deemed to be highly effective, which results in changes in fair value being recorded within accumulated other comprehensive income, a component of shareholder’s equity. We have elected not to offset net derivative positions in the financial statements. Accordingly, we do not offset such derivative positions against the fair value of amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral under master netting agreements. See Note 6 – Derivative Instruments and Hedging Activities for additional information. Insurance and Claims Costs In addition to insurance obtained from third-party providers, MVIC, a wholly-owned captive subsidiary of DPL, provides insurance coverage solely to us, our subsidiaries and, in some cases, our partners in commonly-owned facilities we operate, for workers’ compensation, general liability, and property damage on an ongoing basis. MVIC maintains an active run-off policy for directors’ and officers’ liability and fiduciary through their expiration in 2017, which may or may not be renewed at that time. Insurance and Claims Costs on DPL’s Consolidated Balance Sheets associated with MVIC include estimated liabilities of approximately $5.4 million and $5.9 million at December 31, 2016 and 2015 , respectively. In addition, DP&L is responsible for claim costs below certain coverage thresholds of MVIC for the insurance coverage noted above. DP&L has estimated liabilities for medical, life, disability, and other reserves for claims costs below certain coverage thresholds of third-party providers of approximately $12.0 million and $13.7 million at December 31, 2016 and 2015 , respectively, within Other current liabilities and Other deferred credits on the balance sheets. The estimated liabilities for workers’ compensation, medical, life and disability costs at DP&L are actuarially determined using certain assumptions. There is uncertainty associated with these loss estimates and actual results may differ from the estimates. Modification of these loss estimates based on experience and changed circumstances is reflected in the period in which the estimate is re-evaluated. Pension and Postretirement Benefits We recognize, in our Consolidated Balance Sheets, an asset or liability reflecting the funded status of pension and other postretirement plans with current-year changes in the funded status recognized in AOCI, except for those portions of our pension and postretirement obligations that can be recovered through future rates. All plan assets are recorded at fair value. We follow the measurement date provisions of the accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans. We account for and disclose pension and postemployment benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postemployment plans. These GAAP provisions require the use of assumptions, such as the discount rate for liabilities and long-term rate of return on assets, in determining the obligations, annual cost, and funding requirements of the plans. Effective January 1, 2016, we applied a disaggregated discount rate approach for determining service cost and interest cost for its defined benefit pension plans and post-retirement plans. This approach is consistent with the requirements of FASC 715 and is considered to be preferential to the aggregated single rate discount approach, which has historically been used in the U.S., because it is more consistent with the philosophy of a full yield curve valuation. The change in discount rate approach did not have an impact on the measurement of the benefit obligations at December 31, 2015 or 2016, nor will it impact future remeasurements. This change in approach impacted the service cost and interest cost recorded in 2016 and will impact future years. It also impacted the actuarial gains and losses recorded in 2016 and will impact future years, as well as the amortization thereof. The 2016 service costs and interest costs included in Note 10 – Benefit Plans reflect the change in methodology described above. The impact of the change in approach on service costs and interest costs in 2016 is shown below: $ in millions 2016 Service Cost 2016 Interest Cost Disaggregated rate approach Aggregate rate approach Impact of change Disaggregated rate approach Aggregate rate approach Impact of change Total Pension $ 5.7 $ 6.1 $ (0.4 ) $ 14.7 $ 17.9 $ (3.2 ) Total Postretirement Benefits 0.2 0.2 — 0.6 0.7 (0.1 ) Total $ 5.9 $ 6.3 $ (0.4 ) $ 15.3 $ 18.6 $ (3.3 ) See Note 10 – Benefit Plans for more information. Related Party Transactions In the normal course of business, DPL enters into transactions with related parties. All material intercompany accounts and transactions are eliminated in DPL’s Consolidated Financial Statements. See Note 13 – Related Party Transactions for more information on Related Party Transactions. DPL Capital Trust II DPL has a wholly-owned business trust, DPL Capital Trust II (the Trust), formed for the purpose of issuing trust capital securities to third-party investors. Effective in 2003, DPL deconsolidated the Trust upon adoption of the accounting standards related to variable interest entities and currently treats the Trust as a nonconsolidated subsidiary. The Trust holds mandatorily redeemable trust capital securities. The investment in the Trust, which amounts to $0.3 million and $0.3 million at December 31, 2016 and 2015 , respectively, is included in Other deferred assets within Other noncurrent assets. DPL also has a note payable to the Trust amounting to $15.6 million and $15.6 million at December 31, 2016 and December 31, 2015 , respectively, that was established upon the Trust’s deconsolidation in 2003. See Note 8 – Debt for additional information. In addition to the obligations under the note payable mentioned above, DPL also agreed to a security obligation which represents a full and unconditional guarantee of payments to the capital security holders of the Trust. New accounting pronouncements The following table provides a brief description of recent accounting pronouncements that could have a material impact on our consolidated financial statements: Accounting Standard Description Date of Adoption Effect on the financial statements upon adoption New Accounting Standards Adopted 2016-19 - Technical Corrections and Improvements This standard clarifies guidance that affects the implementation of ASU 2015-05. It clarifies that the license of internal-use software shall be accounted for as the acquisition of an intangible asset. Transition method: retrospective. December 31, 2016 Capitalized software of $59.9 million and its corresponding amortization of $35.3 million previously classified within property, plant and equipment were reclassified to intangibles as of December 31, 2015. 2015-15, Interest - Imputation of Interest (Subtopic 835-30) Given the absence of authoritative guidance within ASU 2015-03, this standard clarifies that the SEC Staff would not object to an entity presenting debt issuance costs related to line-of-credit arrangements as an asset that is subsequently amortized ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. Transition method: retrospective. January 1, 2016 Deferred financing costs related to lines-of-credit of approximately $3.1 million recorded within Other deferred assets were not reclassified. Accounting Standard Description Date of Adoption Effect on the financial statements upon adoption 2015-03, Interest - Imputation of Interest (Subtopic 835-30) The standard simplifies the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the standard. Transition method: retrospective. January 1, 2016 Deferred financing costs of approximately $2.1 million previously classified within Other prepayments and current assets and $14.0 million previously classified within Other deferred assets were reclassified to reduce the related debt liabilities. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis The standard makes targeted amendments to the current consolidation guidance and ends the deferral granted to investment companies from applying the VIE guidance. The standard amends the evaluation of whether (1) fees paid to a decision-maker or service providers represent a variable interest, (2) a limited partnership or similar entity has the characteristics of a VIE and (3) a reporting entity is the primary beneficiary of a VIE. Transition method: retrospective. January 1, 2016 There were no changes to the consolidation conclusions. 2014-15, “Presentation of Financial Statements - Going Concern (Subtopic 205-40) The standard requires management to evaluate whether there are conditions or events, considered in aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. There are required disclosures if substantial doubt is identified including documentation of principal conditions or events that raised substantial doubt about the entity’s ability to continue as a going concern (before consideration of management’s plans), management’s evaluation of the significance of those conditions or events in relation to the entity’s ability to meet its obligations, and management’s plans that alleviated substantial doubt about the entity’s ability to continue as a going concern. December 31, 2016 Adoption of this standard had no impact on our consolidated financial statements. New Accounting Standards Issued But Not Yet Effective 2017-04, Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment This standard simplifies the accounting for goodwill impairment by removing the requirement to calculate the implied fair value. Instead, it requires that an entity records an impairment charge based on the excess of a reporting unit's carrying amount over its fair value. January 1, 2020. Early adoption is permitted as of January 1, 2017. We are currently evaluating the impact of adopting the standard on our consolidated financial statements. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business This standard provides guidance to assist the entities with evaluating when a set of transferred assets and activities is a business. January 1, 2018. Early adoption is permitted We are currently evaluating the impact of adopting the standard on our consolidated financial statements. 2016-18, Statement of Cash Flows (Topic 320): Restricted Cash (a consensus of the FASB Emerging Issues Task Force) This standard requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. Transition method: retrospective. January 1, 2018 Early adoption is permitted. We are currently evaluating the impact of adopting the standard on our consolidated financial statements. 2016-17, Consolidation (Topic 810): Interest Held Through Related Parties That are Under Common Control States that businesses deciding whether they are primary beneficiaries can consider indirect interests held through related parties that are under common control on a proportionate basis as opposed to in their entirety. January 1, 2017 Early adoption is permitted. Transition is retrospective to all relevant prior periods beginning with the fiscal year in which ASU 2015-02 was initially applied. 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory This standard requires that an entity recognizes the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. Transition method: modified retrospective. January 1, 2018. Early adoption is permitted. We are currently evaluating the impact of adopting the standard on our consolidated financial statements. Accounting Standard Description Date of Adoption Effect on the financial statements upon adoption 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Receipts and Cash Payments (a consensus of the Emerging Issues Task Force) This standard provides specific guidance on how certain cash transactions are presented and classified in the statement of cash flows. Transition method: retrospective. January 1, 2018. Early adoption is permitted. We are currently evaluating the impact of adopting the standard on our consolidated financial statements. We do not anticipate a material effect on our consolidated financial statements. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments The standard updates the impairment model for financial assets measured at amortized cost to an expected loss model rather than an incurred loss model. It also allows for the presentation of credit losses on available-for-sale debt securities as an allowance rather than a write down. Transition method: various. January 1, 2020. Early adoption is permitted only as of January 1, 2019. We are currently evaluating the impact of adopting the standard on our consolidated f |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Significant Accounting Policies [Line Items] | |
Overview and Summary of Significant Accounting Policies | Overview and Summary of Significant Accounting Policies Description of Business DP&L is a public utility incorporated in 1911 under the laws of Ohio. Beginning in 2001, Ohio law gave Ohio consumers the right to choose the electric generation supplier from whom they purchase retail generation service, however transmission and distribu tion services are still regulated. DP&L has the exclusive right to provide such service to its approximately 519,000 customers located in West Central Ohio. Additionally, DP&L procures and provides retail SSO electric service to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio and generates electricity at five coal-fired power stations. Beginning January 2016, all of the electric supply for SSO customers is competitively bid. Principal industries located in DP&L’s service territory include automotive, food processing, paper, plastic, manufacturing and defense. DP&L's sales reflect the gen eral economic conditions, seasonal weather patterns of the area and the market price of electricity. DP&L sells energy and capacity into the wholesale market. Through December 31, 2015, DP&L's generation was also used to provide electricity to its SSO customers, as it transitioned to a competitive bidding structure in 2014 and 2015, and also sold electricity to DPLER, an affiliate, to satisfy the electric requirements of DPLER's retail customers. DP&L has two segments, the T&D segment and the Generation segment. See Note 13 – Business Segments for more information relating to reportable segments. On December 30, 2013, DP&L filed an application with the PUCO stating its plan to transfer or sell its generation assets. On July 14, 2014, DP&L announced its decision to retain DP&L’s generation assets. On September 17, 2014, the PUCO ordered that DP&L’s application as amended and updated was approved. DP&L continues to look at multiple options to effectuate the separation, including transfer into an unregulated affiliate of DPL or through a sale. DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators, while its generation business is deemed competitive under Ohio law. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates, and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs. DP&L employed 1,160 people at January 31, 2017 . Approximately 63% of all employees are under a collective bargaining agreement which expires on October 31, 2017 . Financial Statement Presentation DP&L does not have any subsidiaries. DP&L has undivided ownership interests in five electric generating facilities and numerous transmission facilities. These undivided interests in jointly-owned facilities are accounted for on a pro rata basis in DP&L’s Financial Statements. We have evaluated subsequent events through the date this report is issued. Certain amounts from prior periods have been reclassified to conform to the current period presentation. See “Intangibles” below for additional information. The preparation of financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the revenues and expenses of the periods reported. Actual results could differ from these estimates. Significant items subject to such estimates and judgments include: the carrying value of Property, plant and equipment; unbilled revenues; the valuation of derivative instruments; the valuation of insurance and claims liabilities; the valuation of allowances for receivables and deferred income taxes; regulatory assets and liabilities; reserves recorded for income tax exposures; litigation; contingencies; the valuation of AROs; and assets and liabilities related to employee benefits. Revenue Recognition Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. We consider revenue realized, or realizable, and earned when persuasive evidence of an arrangement exists, the products or services have been provided to the customer, the sales price is fixed or determinable, and collection is reasonably assured. Energy sales to customers are based on the reading of their meters that occurs on a systematic basis throughout the month. We recognize the revenues on our statements of operations using an accrual method for retail and other energy sales that have not yet been billed, but where electricity has been consumed. This is termed “unbilled revenues” and is a widely recognized and accepted practice for utilities. At the end of each month, unbilled revenues are determined by the estimation of unbilled energy provided to customers since the date of the last meter reading, estimated line losses, the assignment of unbilled energy provided to customer classes and the average rate per customer class. All of the power produced at the generation stations is sold to an RTO and we in turn purchase it back from the RTO to supply our customers. The power sales and purchases within DP&L’s service territory are reported on a net hourly basis as revenues or purchased power on our Statements of Operations. We record expenses when purchased electricity is received and when expenses are incurred, with the exception of the ineffective portion of certain power purchase contracts that are derivatives and qualify for hedge accounting. We also have certain derivative contracts that do not qualify for hedge accounting, and their unrealized gains or losses are recorded prior to the receipt of electricity. Allowance for Uncollectible Accounts We establish provisions for uncollectible accounts by using both historical average loss percentages to project future losses and by establishing specific provisions for known credit issues. Amounts are written off when reasonable collections efforts have been exhausted. Property, Plant and Equipment We record our ownership share of our undivided interest in jointly-held stations as an asset in property, plant and equipment. New property, plant and equipment additions are stated at cost. For regulated transmission and distribution property, cost includes direct labor and material, allocable overhead expenses and an allowance for funds used during construction (AFUDC). AFUDC represents the cost of borrowed funds and equity used to finance regulated construction projects. For non-regulated property, cost also includes capitalized interest. Capitalization of AFUDC and interest ceases at either project completion or at the date specified by regulators. AFUDC and capitalized interest was $2.7 million , $2.0 million , and $1.5 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. For unregulated generation property, cost includes direct labor and material, allocable overhead expenses and interest capitalized during construction using the provisions of GAAP relating to the accounting for capitalized interest. For substantially all depreciable property, when a unit of property is retired, the original cost of that property less any salvage value is charged to Accumulated depreciation and amortization, consistent with composite depreciation practices. Property is evaluated for impairment when events or changes in circumstances indicate that its carrying amount may not be recoverable. Repairs and Maintenance Costs associated with maintenance activities, primarily power station outages, are recognized at the time the work is performed. These costs, which include labor, materials and supplies, and outside services required to maintain equipment and facilities, are capitalized or expensed based on defined units of property. Depreciation Depreciation expense is calculated using the straight-line method, which allocates the cost of property over its estimated useful life. For DP&L’s generation, transmission and distribution assets, straight-line depreciation is applied monthly on an average composite basis using group rates. For DP&L’s generation, transmission, and distribution assets, straight-line depreciation is applied on an average annual composite basis using group rates that approximated 4.6% in 2016 , 2.5% in 2015 and 2.8% in 2014 . Depreciation was $110.0 million , $132.7 million and $141.6 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. During the fourth quarter of 2015, DP&L tested the recoverability of long-lived assets at certain generating stations. See Note 12 – Related Party Transactions for more information. Gradual decreases in power prices as well as lower estimates of future capacity prices in conjunction with the DP&L reporting unit of DPL failing step 1 of the annual goodwill impairment test were collectively determined to be an impairment indicator. Regulatory Accounting As a regulated utility, we apply the provisions of FASC 980 “Regulated Operations”, which gives recognition to the ratemaking and accounting practices of the PUCO and the FERC. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory assets can also represent performance incentives permitted by the regulator. Regulatory assets have been included as allowable costs for ratemaking purposes, as authorized by the PUCO or established regulatory practices. Regulatory liabilities generally represent obligations to make refunds or future rate reductions to customers for previous over collections or the deferral of revenues collected for costs that DP&L expects to incur in the future. The deferral of costs (as regulatory assets) is appropriate only when the future recovery of such costs is probable. In assessing probability, we consider such factors as specific orders from the PUCO or FERC, regulatory precedent and the current regulatory environment. To the extent recovery of costs is no longer deemed probable, related regulatory assets would be required to be expensed in current period earnings. Our regulatory assets and liabilities have been created pursuant to a specific order of the PUCO or FERC or established regulatory practices, such as other utilities under the jurisdiction of the PUCO or FERC being granted recovery of similar costs. It is probable, but not certain, that these regulatory assets will be recoverable, subject to PUCO or FERC approval. Regulatory assets and liabilities are classified as current or non-current based on the term in which recovery is expected. See Note 3 – Regulatory Matters for more information. Inventories Inventories are carried at average cost and include coal, limestone, oil and gas used for electric generation, and materials and supplies used for utility operations. Intangibles Intangibles include software, emission allowances and renewable energy credits. Emission allowances are carried on a first-in, first-out (FIFO) basis for purchased emission allowances. Net gains or losses on the sale of excess emission allowances, representing the difference between the sales proceeds and the cost of emission allowances, are recorded as a component of our fuel costs and are reflected in Operating income when realized. Emission allowances are amortized as they are used in our operations on a FIFO basis. Renewable energy credits are carried on a weighted average cost basis and amortized as they are used or retired. Intangible assets include capitalized software of $78.5 million and $73.9 million and its corresponding amortization of $56.4 million and $49.2 million previously classified within Total net property, plant and equipment that were reclassified to Intangible assets as of December 31, 2016 and 2015 , respectively. These assets are amortized over seven years. See “ New Accounting Pronouncements ” below for additional information. A mortization expense was $7.5 million , $8.2 million and $8.0 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. The estimated amortization expense of this internal-use software is $15.3 million ( $6.1 million in 2017, $5.6 million in 2018 and $3.6 million in 2019 ). Income Taxes Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases. We establish an allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. Our tax positions are evaluated under a more likely than not recognition threshold and measurement analysis before they are recognized for financial statement reporting. Uncertain tax positions have been classified as noncurrent income tax liabilities unless expected to be paid within one year. Our policy for interest and penalties is to recognize interest and penalties as a component of the provision for income taxes in the Statement of Operations. Income taxes payable, which are includable in allowable costs for ratemaking purposes in future years, are recorded as regulatory assets with a corresponding deferred tax liability. Investment tax credits that reduced federal income taxes in the years they arose have been deferred and are being amortized to income over the useful lives of the properties in accordance with regulatory treatment. See Note 3 – Regulatory Matters for additional information. DPL and its subsidiaries file U.S. federal income tax returns as part of the consolidated U.S. income tax return filed by AES. The consolidated tax liability is allocated to each subsidiary based on the separate return method which is specified in our tax allocation agreement and which provides a consistent, systematic and rational approach. See Note 8 – Income Taxes for additional information. Financial Instruments We classify our investments in debt and equity financial instruments of publicly traded entities into different categories: held-to-maturity and available-for-sale. Available-for-sale securities are carried at fair value and unrealized gains and losses on those securities, net of deferred income taxes, are presented as a separate component of shareholder's equity. Other-than-temporary declines in value are recognized currently in earnings. Financial instruments classified as held-to-maturity are carried at amortized cost. The cost bases for public equity security and fixed maturity investments are average cost and amortized cost, respectively. Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities DP&L collects certain excise taxes levied by state or local governments from its customers. DP&L’s excise taxes and certain other taxes are accounted for on a net basis and recorded as a reduction in revenues in the accompanying Statements of Operations. The amounts for the years ended December 31, 2016 , 2015 and 2014 were $50.9 million , $49.9 million and $50.8 million , respectively. Cash and Cash Equivalents Cash and cash equivalents are stated at cost, which approximates fair value. All highly liquid short-term investments with original maturities of three months or less are considered cash equivalents. Restricted Cash Restricted cash includes cash which is restricted as to withdrawal or usage. The nature of the restrictions includes restrictions imposed by agreements related to deposits held as collateral. At December 31, 2015, restricted cash also includes cash received in connection with the January 1, 2016 contract termination canceling DP&L's power sales contracts with DPLER. Financial Derivatives All derivatives are recognized as either assets or liabilities in the balance sheets and are measured at fair value. Changes in the fair value are recorded in earnings unless the derivative is designated as a cash flow hedge of a forecasted transaction or it qualifies for the normal purchases and sales exception. We use forward contracts to reduce our exposure to changes in energy and commodity prices and as a hedge against the risk of changes in cash flows associated with expected electricity purchases. We hold forward sales contracts that hedge against the risk of changes in cash flows associated with power sales during periods of projected generation facility availability. We use cash flow hedge accounting when the hedge or a portion of the hedge is deemed to be highly effective, which results in changes in fair value being recorded within accumulated other comprehensive income, a component of shareholder’s equity. We have elected not to offset net derivative positions in the financial statements. Accordingly, we do not offset such derivative positions against the fair value of amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral under master netting agreements. See Note 6 – Derivative Instruments and Hedging Activities for additional information. Insurance and Claims Costs In addition to insurance obtained from third-party providers, MVIC, a wholly-owned captive subsidiary of DPL, provides insurance coverage solely to us, other DPL subsidiaries and, in some cases, our partners in commonly-owned facilities we operate, for workers’ compensation, general liability, and property damage on an ongoing basis. MVIC maintains an active run-off policy for directors’ and officers’ liability and fiduciary through their expiration in 2017, which may or may not be renewed at that time. DP&L is responsible for claim costs below certain coverage thresholds of MVIC and third party insurers for the insurance coverage noted above. DP&L has estimated liabilities for medical, life, disability, and other reserves for claims costs below certain coverage thresholds of MVIC and third-party providers. We recorded these additional insurance and claims costs of approximately $11.8 million and $13.7 million at December 31, 2016 and 2015 , respectively, within Other current liabilities and Other deferred credits on the balance sheets. The estimated liabilities for workers’ compensation, medical, life and disability costs at DP&L are actuarially determined using certain assumptions. There is uncertainty associated with these loss estimates and actual results may differ from the estimates. Modification of these loss estimates based on experience and changed circumstances is reflected in the period in which the estimate is re-evaluated. Pension and Postretirement Benefits We recognize, in our Balance Sheets, an asset or liability reflecting the funded status of pension and other postretirement plans with current-year changes in the funded status recognized in AOCI, except for those portions of our pension and postretirement obligations that can be recovered through future rates. All plan assets are recorded at fair value. We follow the measurement date provisions of the accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans. We account for and disclose pension and postemployment benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postemployment plans. These GAAP provisions require the use of assumptions, such as the discount rate for liabilities and long-term rate of return on assets, in determining the obligations, annual cost, and funding requirements of the plans. Effective January 1, 2016, we applied a disaggregated discount rate approach for determining service cost and interest cost for its defined benefit pension plans and post-retirement plans. This approach is consistent with the requirements of FASC 715 and is considered to be preferential to the aggregated single rate discount approach, which has historically been used in the U.S., because it is more consistent with the philosophy of a full yield curve valuation. The change in discount rate approach did not have an impact on the measurement of the benefit obligations at December 31, 2015 or 2016, nor will it impact future remeasurements. This change in approach impacted the service cost and interest cost recorded in 2016 and will impact future years. It also impacted the actuarial gains and losses recorded in 2016 and will impact future years, as well as the amortization thereof. The 2016 service costs and interest costs included in Note 9 – Benefit Plans reflect the change in methodology described above. The impact of the change in approach on service costs and interest costs in 2016 is shown below: $ in millions 2016 Service Cost 2016 Interest Cost Disaggregated rate approach Aggregate rate approach Impact of change Disaggregated rate approach Aggregate rate approach Impact of change Total Pension $ 5.7 $ 6.1 $ (0.4 ) $ 14.7 $ 17.9 $ (3.2 ) Total Postretirement Benefits 0.2 0.2 — 0.6 0.7 (0.1 ) Total $ 5.9 $ 6.3 $ (0.4 ) $ 15.3 $ 18.6 $ (3.3 ) See Note 9 – Benefit Plans for more information. Related Party Transactions In the normal course of business, DP&L enters into transactions with other subsidiaries of DPL or AES. See Note 12 – Related Party Transactions for additional information on Related Party Transactions. New accounting pronouncements The following table provides a brief description of recent accounting pronouncements that could have a material impact on our financial statements: Accounting Standard Description Date of Adoption Effect on the financial statements upon adoption New Accounting Standards Adopted 2016-19 - Technical Corrections and Improvements This standard clarifies guidance that affects the implementation of ASU 2015-05. It clarifies that the license of internal-use software shall be accounted for as the acquisition of an intangible asset. Transition method: retrospective. December 31, 2016 Capitalized software of $78.5 million and its corresponding amortization of $56.4 million previously classified within property, plant and equipment were reclassified to intangibles as of December 31, 2016. 2015-15, Interest - Imputation of Interest (Subtopic 835-30) Given the absence of authoritative guidance within ASU 2015-03, this standard clarifies that the SEC Staff would not object to an entity presenting debt issuance costs related to line-of-credit arrangements as an asset that is subsequently amortized ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. Transition method: retrospective. January 1, 2016 Deferred financing costs related to lines-of-credit of approximately $0.7 million recorded within Other deferred assets were not reclassified. 2015-03, Interest - Imputation of Interest (Subtopic 835-30) The standard simplifies the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the standard. Transition method: retrospective. January 1, 2016 Deferred financing costs of approximately $1.8 million previously classified within Other prepayments and current assets and $4.5 million previously classified within Other deferred assets were reclassified to reduce the related debt liabilities. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis The standard makes targeted amendments to the current consolidation guidance and ends the deferral granted to investment companies from applying the VIE guidance. The standard amends the evaluation of whether (1) fees paid to a decision-maker or service providers represent a variable interest, (2) a limited partnership or similar entity has the characteristics of a VIE and (3) a reporting entity is the primary beneficiary of a VIE. Transition method: retrospective. January 1, 2016 There were no changes to the consolidation conclusions. 2014-15, “Presentation of Financial Statements - Going Concern (Subtopic 205-40) The standard requires management to evaluate whether there are conditions or events, considered in aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. There are required disclosures if substantial doubt is identified including documentation of principal conditions or events that raised substantial doubt about the entity’s ability to continue as a going concern (before consideration of management’s plans), management’s evaluation of the significance of those conditions or events in relation to the entity’s ability to meet its obligations, and management’s plans that alleviated substantial doubt about the entity’s ability to continue as a going concern. December 31, 2016 Adoption of this standard had no impact on our financial statements. Accounting Standard Description Date of Adoption Effect on the financial statements upon adoption New Accounting Standards Issued But Not Yet Effective 2017-04, Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment This standard simplifies the accounting for goodwill impairment by removing the requirement to calculate the implied fair value. Instead, it requires that an entity records an impairment charge based on the excess of a reporting unit's carrying amount over its fair value. January 1, 2020. Early adoption is permitted as of January 1, 2017. We are currently evaluating the impact of adopting the standard on our financial statements. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business This standard provides guidance to assist the entities with evaluating when a set of transferred assets and activities is a business. January 1, 2018. Early adoption is permitted We are currently evaluating the impact of adopting the standard on our financial statements. 2016-18, Statement of Cash Flows (Topic 320): Restricted Cash (a consensus of the FASB Emerging Issues Task Force) This standard requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. Transition method: retrospective. January 1, 2018 Early adoption is permitted. We are currently evaluating the impact of adopting the standard on our financial statements. 2016-17, Consolidation (Topic 810): Interest Held Through Related Parties That are Under Common Control States that businesses deciding whether they are primary beneficiaries can consider indirect interests held through related parties that are under common control on a proportionate basis as opposed to in their entirety. January 1, 2017 Early adoption is permitted. Transition is retrospective to all relevant prior periods beginning with the fiscal year in which ASU 2015-02 was initially applied. 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory This standard requires that an entity recognizes the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. Transition method: modified retrospective. January 1, 2018. Early adoption is permitted. We are currently evaluating the impact of adopting the standard on our financial statements. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Receipts and Cash Payments (a consensus of the Emerging Issues Task Force) This standard provides specific guidance on how certain cash transactions are presented and classified in the statement of cash flows. Transition method: retrospective. January 1, 2018. Early adoption is permitted. We are currently evaluating the impact of adopting the standard on our financial statements. We do not anticipate a material effect on our financial statements. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments The standard updates the impairment model for financial assets measured at amortized cost to an expected loss model rather than an incurred loss model. It also allows for the presentation of credit losses on available-for-sale debt securities as an allowance rather than a write down. Transition method: various. January 1, 2020. Early adoption is permitted only as of January 1, 2019. We are currently evaluating the impact of adopting the standard on our financial statements. No transition method has been selected yet. 2016-11, Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting Removes some of the Emerging Issues Task Force (EITF) guidance for revenue recognition and hedge accounting from U.S. GAAP to reflect announcements the SEC staff made to the task force in March. January 1, 2018. Earlier application is permitted only as of January 1, 2017. We are currently evaluating the impact of adopting the standard on our financial statements. Accounting Standard Description Date of Adoption Effect on the financial statements upon adoption 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting The standard simplifies the following aspects of accounting for share-based payment awards: accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, statutory tax withholding requirements, classification of awards as either equity or liabilities and classification of employee taxes paid on statement of cash flows when an employer withholds shares for tax-withholding purposes. Transition method: The recording of excess tax benefits and tax deficiencies arising from vesting or settlement will be applied prospectively. The elimination of the requirement that excess tax benefits be realized before they are recognized will be adopted on a modified retrospective basis with a cumulative adjustment to the opening balance sheet. January 1, 2017. Early adoption is permitted. The primary effect of adoption will be the recognition of excess tax benefits in our provision for income taxes in the period when the awards vest or are settled, rather than in paid-in-capital in the period when the excess tax benefits are realized. We will continue to estimate the number of awards that are expected to vest in our determination of the related periodic compensation cost. 2016-06, Derivatives and Hedging (Topic 815) - Contingent Put and Call Options in Debt Instruments This standard clarifies the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. When a call (put) option is contingently exercisable, an entity no longer has to assess whether the event that triggers the ability to exercise a call (put) option is related to interest rates or credit risks. Transition method: a modified retrospective basis to existing debt instruments as of the effective date. January 1, 2017. Early adoption is permitted. We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact on our financial statements. 2016-05, Derivatives and Hedging (Topic 815) - Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships The standard clarifies that a change in the counterparty to a derivative instrument that has been designated as the hedging instrument under Topic 815 does not require de-designation of that hedging relationship provided that all other hedge accounting criteria (including those in paragraphs 815-20-35-14 through 35-18) continue to be met. Transition method: prospective or a modified retrospective basis. January 1, 2017. Early adoption is permitted. We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact on our financial statements. No transition method has been selected yet. 2016-02, Leases (Topic 842) The standard creates Topic 842, Leases which su |
Supplemental Financial Informat
Supplemental Financial Information | 12 Months Ended |
Dec. 31, 2016 | |
Supplemental Financial Information [Line Items] | |
Supplemental Financial Information | Supplemental Financial Information December 31, $ in millions 2016 2015 Accounts receivable, net Unbilled revenue $ 43.0 $ 43.3 Customer receivables 73.9 56.4 Amounts due from partners in jointly-owned stations 12.7 16.0 Other 6.7 6.0 Provisions for uncollectible accounts (1.2 ) (0.8 ) Total accounts receivable, net $ 135.1 $ 120.9 Inventories Fuel and limestone $ 38.9 $ 72.2 Plant materials and supplies 36.6 34.9 Other 1.7 2.0 Total inventories, at average cost $ 77.2 $ 109.1 Accounts receivable of $31.0 million as of December 31, 2015 have been excluded from the above table as they have been reclassified as "Assets held for sale". See Note 16 – Discontinued Operations . Accumulated Other Comprehensive Income / (Loss) The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the years ended December 31, 2016 , 2015 and 2014 are as follows: Details about Accumulated Other Comprehensive Income / (Loss) Components Affected line item in the Consolidated Statements of Operations Years ended December 31, $ in millions 2016 2015 2014 Gains and losses on Available-for-sale securities activity (Note 5): Other income $ — $ — $ 0.4 Tax expense — — (0.2 ) Net of income taxes — — 0.2 Gains and losses on cash flow hedges (Note 6): Interest Expense (1.0 ) (1.1 ) (1.3 ) Revenue (55.3 ) (18.7 ) 28.4 Purchased power 9.9 4.4 (0.7 ) Total before income taxes (46.4 ) (15.4 ) 26.4 Tax benefit / (expense) 16.7 5.4 (9.5 ) Net of income taxes (29.7 ) (10.0 ) 16.9 Amortization of defined benefit pension items (Note 10): Operations and maintenance 1.6 0.4 — Tax expense (0.6 ) (0.2 ) — Net of income taxes 1.0 0.2 — Total reclassifications for the period, net of income taxes $ (28.7 ) $ (9.8 ) $ 17.1 The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the years ended December 31, 2016 and 2015 are as follows: $ in millions Gains / (losses) on available-for-sale securities Gains / (losses) on cash flow hedges Change in unfunded pension obligation Total Balance at December 31, 2014 $ 0.5 $ 18.5 $ (11.5 ) $ 7.5 Other comprehensive income / (loss) before reclassifications (0.1 ) 18.2 1.6 19.7 Amounts reclassified from accumulated other comprehensive income / (loss) — (10.0 ) 0.2 (9.8 ) Net current period other comprehensive income / (loss) (0.1 ) 8.2 1.8 9.9 Balance at December 31, 2015 0.4 26.7 (9.7 ) 17.4 Other comprehensive income / (loss) before reclassifications 0.2 16.1 (4.7 ) 11.6 Amounts reclassified from accumulated other comprehensive income / (loss) — (29.7 ) 1.0 (28.7 ) Net current period other comprehensive income / (loss) 0.2 (13.6 ) (3.7 ) (17.1 ) Balance at December 31, 2016 $ 0.6 $ 13.1 $ (13.4 ) $ 0.3 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Supplemental Financial Information [Line Items] | |
Supplemental Financial Information | Supplemental Financial Information December 31, $ in millions 2016 2015 Accounts receivable, net Unbilled revenue $ 43.0 $ 43.3 Customer receivables 71.2 54.1 Amounts due from partners in jointly-owned stations 12.7 16.0 Other 8.9 6.9 Provisions for uncollectible accounts (1.2 ) (0.8 ) Total accounts receivable, net $ 134.6 $ 119.5 Inventories Fuel and limestone $ 38.8 $ 72.2 Plant materials and supplies 35.3 33.7 Other 1.7 2.1 Total inventories, at average cost $ 75.8 $ 108.0 Accumulated Other Comprehensive Income (Loss) The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the years ended December 31, 2016 , 2015 and 2014 are as follows: Details about Accumulated Other Comprehensive Income / (Loss) Components Affected line item in the Statements of Operations Years ended December 31, $ in millions 2016 2015 2014 Gains and losses on Available-for-sale securities activity (Note 5): Other income $ — $ — $ 0.4 Tax expense — — (0.2 ) Net of income taxes — — 0.2 Gains and losses on cash flow hedges (Note 6): Interest expense (1.0 ) (1.1 ) (1.1 ) Revenue (55.3 ) (18.7 ) 28.4 Purchased power 9.9 4.4 (0.4 ) Total before income taxes (46.4 ) (15.4 ) 26.9 Tax benefit / (expense) 16.4 5.6 (11.5 ) Net of income taxes (30.0 ) (9.8 ) 15.4 Amortization of defined benefit pension items (Note 9): Operation and maintenance 7.7 5.6 4.1 Tax expense (1.8 ) (1.9 ) (1.4 ) Net of income taxes 5.9 3.7 2.7 Total reclassifications for the period, net of income taxes $ (24.1 ) $ (6.1 ) $ 18.3 The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the years ended December 31, 2016 and 2015 are as follows: $ in millions Gains / (losses) on available-for-sale securities Gains / (losses) on cash flow hedges Change in unfunded pension obligation Total Balance at December 31, 2014 $ 0.7 $ 2.8 $ (45.8 ) $ (42.3 ) Other comprehensive income / (loss) before reclassifications (0.2 ) 18.2 1.7 19.7 Amounts reclassified from accumulated other comprehensive income / (loss) — (9.8 ) 3.7 (6.1 ) Net current period other comprehensive income / (loss) (0.2 ) 8.4 5.4 13.6 Balance at December 31, 2015 0.5 11.2 (40.4 ) (28.7 ) Other comprehensive income / (loss) before reclassifications 0.2 16.1 (6.0 ) 10.3 Amounts reclassified from accumulated other comprehensive income / (loss) — (30.0 ) 5.9 (24.1 ) Net current period other comprehensive income / (loss) 0.2 (13.9 ) (0.1 ) (13.8 ) Balance at December 31, 2016 $ 0.7 $ (2.7 ) $ (40.5 ) $ (42.5 ) |
Regulatory Assets and Liabiliti
Regulatory Assets and Liabilities | 12 Months Ended |
Dec. 31, 2016 | |
Regulatory Assets [Line Items] | |
Regulatory Assets and Liabilities | Regulatory Matters DP&L originally filed its ESP 3 seeking an effective date of January 1, 2017. On October 11, 2016, DP&L amended the application requesting to collect $145.0 million per year for seven years supporting the alternative described in the original filing, named the Distribution Modernization Rider. This plan establishes the terms and conditions for DP&L’s SSO to customers that do not choose a competitive retail electric supplier. In its plan, DP&L recommends including renewable energy attributes as part of the product that is competitively bid, and seeks recovery of approximately $10.5 million of regulatory assets. The plan also proposes a new Distribution Investment Rider to allow DP&L to recover costs associated with future distribution equipment and infrastructure needs. Additionally, the plan establishes new riders set initially at zero, related to energy reductions from DP&L’s energy efficiency programs, and certain environmental liabilities DP&L may incur. On January 30, 2017, DP&L , in conjunction with nine intervening parties, filed a settlement in the ESP 3 case, which is subject to PUCO approval. DP&L and the intervening parties agreed to a six -year settlement that provides a framework for energy rates and defines components which include, but are not limited to, the following: • The establishment of a five -year Distribution Modernization Rider designed to collect $90.0 million in revenue per year to pay debt obligations at DPL and DP&L and position DP&L to modernize and/or maintain its transmission and distribution infrastructure; • The establishment of a Distribution Investment Rider for distribution investments, with one component designed to collect $35.0 million in revenue per year to enable the implementation of smart grid and advanced metering ending after the fifth year of the term of the ESP; • A commitment by us to separate DP&L’s generation assets from its transmission and distribution assets (if approved by FERC); • A commitment to commence a sale process to sell our ownership interests in the Zimmer, Miami Fort and Conesville coal-fired generation plants; • A commitment to develop or procure wind and/or solar energy projects in Ohio; and • Restrictions on DPL making dividend or tax sharing payments, and various other riders and competitive retail market enhancements. A hearing on the stipulation has been scheduled for March 8, 2017. A final decision by the PUCO is expected at the end of the second quarter or early in the third quarter of 2017. If the PUCO agrees to the proposed settlement, the average residential customer in the DP&L service territory, using 1,000 kWh on DP&L's SSO, can expect a monthly bill increase of $2.39 . There can be no assurance that the ESP 3 stipulation will be approved as filed or on a timely basis, and if the ESP 3 stipulation is not approved on a timely basis or if the final ESP provides for terms that are more adverse than those submitted in DP&L's stipulation, our results of operations, financial condition and cash flows and DPL's ability to meet long-term obligations, in the periods beyond twelve months from the date of this report, could be materially impacted. In connection with any sale or exiting of our generation plants as contemplated by the ESP settlement or otherwise, DPL and DP&L would expect to incur certain cash and non-cash charges, some or all of which could be material to the business and financial condition of DPL and DP&L . Regulatory assets and liabilities In accordance with FASC 980, we have recognized total regulatory assets of $204.0 million and $194.3 million at December 31, 2016 and 2015 , respectively, and total regulatory liabilities of $164.1 million and $151.4 million at December 31, 2016 and 2015 , respectively. Regulatory assets and liabilities are classified as current or non-current based on the term in which recovery is expected. See Note 1 – Overview and Summary of Significant Accounting Policies for accounting policies regarding Regulatory Assets and Liabilities. The following table presents DPL’s Regulatory assets and liabilities: December 31, $ in millions Type of Recovery Amortization Through 2016 2015 Regulatory assets, current: Fuel and purchased power recovery costs A 2016 $ — $ 13.9 Economic development costs A 2017 0.1 0.5 Total regulatory assets, current 0.1 14.4 Regulatory assets, non-current: Pension benefits B Ongoing 97.6 91.6 Deferred recoverable income taxes B/C Ongoing 35.9 36.4 Unrecovered OVEC charges D Undetermined 21.0 10.5 Fuel costs B Undetermined 15.4 12.7 Unamortized loss on reacquired debt B Various 8.0 9.0 Smart grid and advanced metering infrastructure costs D Undetermined 7.3 7.3 Rate case costs D Undetermined 6.3 1.9 Generation separation costs D Undetermined 5.7 3.9 Retail settlement system costs D Undetermined 3.1 3.1 Consumer education campaign D Undetermined 3.0 3.0 Other miscellaneous D Undetermined 0.6 0.5 Total regulatory assets, non-current 203.9 179.9 Total regulatory assets $ 204.0 $ 194.3 Regulatory liabilities, current: Competitive bidding $ 16.1 $ 9.1 Energy efficiency program 14.1 9.2 Transmission costs 3.3 3.7 Reconciliation rider — 2.1 Other miscellaneous 0.2 0.3 Total regulatory liabilities, current 33.7 24.4 Regulatory liabilities, non-current: Estimated costs of removal - regulated property 126.5 121.8 Postretirement benefits 3.9 5.2 Total regulatory liabilities, non-current 130.4 127.0 Total regulatory liabilities $ 164.1 $ 151.4 A – Recovery of incurred costs plus rate of return. B – Recovery of incurred costs without a rate of return. C – Balance has an offsetting liability resulting in no effect on rate base. D – Recovery not yet determined, but is probable of occurring in future rate proceedings. Regulatory assets Fuel and purchased power recovery costs represent prudently incurred fuel, purchased power, derivative, emission and other related costs which will be recovered from or returned to customers in the future through the operation of the fuel and purchased power recovery rider. This rider was discontinued in 2016 and the remaining balance was transferred to the Competitive Bid True-up rider. Fuel costs - long term represent unrecovered fuel costs related to DP&L’s fuel rider from 2010 through 2015 resulting from a declining SSO customer base. DP&L has requested recovery of these costs as part of its pending Distribution Rate Case filing. Economic development costs represent costs incurred to promote economic development within the State of Ohio. These costs are being recovered through an Economic Development Rider that is subject to a bi-annual true-up process for any over/under recovery of costs. Pension benefits represent the qualifying FASC 715 “Compensation - Retirement Benefits” costs of our regulated operations that for ratemaking purposes are deferred for future recovery. We recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of OCI, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. This regulatory asset represents the regulated portion that would otherwise be charged as a loss to OCI. Deferred recoverable income taxes represent deferred income tax assets recognized from the normalization of flow-through items as the result of tax benefits previously provided to customers. This is the cumulative flow-through benefit given to regulated customers that will be collected from them in future years. Since currently existing temporary differences between the financial statements and the related tax basis of assets will reverse in subsequent periods, these deferred recoverable income taxes will decrease over time. Unrecovered OVEC charges includes the portion of charges from OVEC that were not recoverable through DP&L’s fuel rider beginning in October 2014. Because the fuel rider was discontinued in 2016, all OVEC costs, net of OVEC revenues received through PJM, are now deferred into this asset. DP&L expects to recover these costs through a future rate proceeding. Unamortized loss on reacquired debt represents losses on long-term debt reacquired or redeemed in prior periods that have been deferred. These deferred losses are being amortized over the lives of the original issues in accordance with FERC and PUCO rules. Smart Grid and AMI costs represent costs incurred as a result of studying and developing distribution system upgrades and the implementation of AMI. On October 19, 2010, DP&L elected to withdraw its case pertaining to the Smart Grid and AMI programs. The PUCO accepted the withdrawal in an order issued on January 5, 2011. The PUCO also indicated that it expects DP&L to continue to monitor other utilities' Smart Grid and AMI programs and to explore the potential benefits of investing in Smart Grid and AMI programs and that DP&L will, when appropriate, file new Smart Grid and/or AMI business cases in the future. This plan is currently under development and we plan to seek recover of these deferred costs in a regulatory rate proceeding in the near future. Based on past PUCO precedent, we believe these costs are probable of future recovery in rates. Rate case costs represent costs associated with preparing a distribution rate case. DP&L has requested recovery of these costs as part of its pending distribution rate case filing. Generation separation costs represent financing, redemption and other costs related to the divestiture of DP&L’s generation assets. The PUCO directed DP&L to divest its generation assets by January 1, 2017. DP&L requested and was granted permission by the PUCO to defer all financing, redemption and related costs it incurs to transfer its generation assets. DP&L has requested recovery of these costs as part of its pending distribution rate case filing. Retail settlement system costs represent costs to implement a retail settlement system that reconciles the energy a CRES supplier delivers to its customers with what its customers actually use. DP&L has requested recovery of these costs as part of its pending Distribution Rate Case filing. Consumer education campaign represents costs for consumer education advertising regarding electric deregulation. DP&L has requested recovery of these costs as part of its pending distribution rate case filing. Regulatory liabilities Competitive bidding represents costs associated with the development and implementation of a competitive bidding process, establishing contracts to supply power for DP&L’s SSO load, as well as the net over/under recovery of the cost of the power purchased from the bid winners. Energy efficiency program costs represent costs incurred to develop and implement various customer programs addressing energy efficiency. These costs are being recovered through an Energy Efficiency Rider (EER) that began July 1, 2009 and that is subject to an annual true-up for any over/under recovery of costs. In addition to recovery of program costs, this rider has allowed for DP&L to recover lost margin associated with decreases in sales as a result of the programs implemented. The authority to recover lost margin included a maximum amount, which DP&L reached in the fourth quarter of 2015. Consequently, we discontinued accruing an asset for lost revenues after the maximum was reached. On December 13, 2016 DP&L filed its Energy Efficiency portfolio case with the PUCO that specifies, among other things, that DP&L can collect lost distribution revenues for 2016 and going forward through the EER. The amount of lost revenues earned and accrued in 2016 is $20.1 million . Based on multiple parties’ agreement and past PUCO precedent on the treatment of lost distribution revenues for other utilities, it is probable, but not certain, DP&L will recover this amount. In addition, this rider provides that DP&L can earn a “shared savings” incentive that is tiered depending upon the level of success the programs reach. In 2015 and 2016, the maximum shared savings was accrued based upon performance, which is equal to $4.5 million after income taxes. Transmission costs represent the costs related to transmission, ancillary service and other PJM-related charges that have been incurred as a member of PJM. On an annual basis, retail rates are adjusted to true-up costs with recovery in rates. Reconciliation rider represents the costs that exceed 10 percent of the base amount of the following riders: Fuel, RPM, Alternative Energy and Competitive Bidding. This rider is in an overcollection position and will be discontinued after this overcollection has been refunded to customers. Estimated costs of removal – regulated property reflect an estimate of amounts collected in customer rates for costs that are expected to be incurred in the future to remove existing transmission and distribution property from service when the property is retired. Postretirement benefits represent the qualifying FASC 715 “Compensation – Retirement Benefits” gains related to our regulated operations that, for ratemaking purposes, are probable of being reflected in future rates. We recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of OCI, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. This regulatory liability represents the regulated portion that would otherwise be reflected as a gain to OCI. |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Regulatory Assets [Line Items] | |
Regulatory Assets and Liabilities | Regulatory Matters DP&L originally filed its ESP 3 seeking an effective date of January 1, 2017. On October 11, 2016, DP&L amended the application requesting to collect $145.0 million per year for seven years supporting the alternative described in the original filing, named the Distribution Modernization Rider. This plan establishes the terms and conditions for DP&L’s SSO to customers that do not choose a competitive retail electric supplier. In its plan, DP&L recommends including renewable energy attributes as part of the product that is competitively bid, and seeks recovery of approximately $10.5 million of regulatory assets. The plan also proposes a new Distribution Investment Rider to allow DP&L to recover costs associated with future distribution equipment and infrastructure needs. Additionally, the plan establishes new riders set initially at zero, related to energy reductions from DP&L’s energy efficiency programs, and certain environmental liabilities DP&L may incur. On January 30, 2017, DP&L , in conjunction with nine intervening parties, filed a settlement in the ESP 3 case, which is subject to PUCO approval. DP&L and the intervening parties agreed to a six -year settlement that provides a framework for energy rates and defines components which include, but are not limited to, the following: • The establishment of a five -year Distribution Modernization Rider designed to collect $90.0 million in revenue per year to pay debt obligations at DPL and DP&L and position DP&L to modernize and/or maintain its transmission and distribution infrastructure; • The establishment of a Distribution Investment Rider for distribution investments, with one component designed to collect $35.0 million in revenue per year to enable the implementation of smart grid and advanced metering ending after the fifth year of the term of the ESP; • A commitment by us to separate DP&L’s generation assets from its transmission and distribution assets (if approved by FERC); • A commitment to commence a sale process to sell our ownership interests in the Zimmer, Miami Fort and Conesville coal-fired generation plants; • A commitment to develop or procure wind and/or solar energy projects in Ohio; and • Restrictions on DPL making dividend or tax sharing payments, and various other riders and competitive retail market enhancements. A hearing on the stipulation has been scheduled for March 8, 2017. A final decision by the PUCO is expected at the end of the second quarter or early in the third quarter of 2017. If the PUCO agrees to the proposed settlement, the average residential customer in the DP&L service territory, using 1,000 kWh on DP&L's SSO, can expect a monthly bill increase of $2.39 . There can be no assurance that the ESP 3 stipulation will be approved as filed or on a timely basis, and if the ESP 3 stipulation is not approved on a timely basis or if the final ESP provides for terms that are more adverse than those submitted in DP&L's stipulation, our results of operations, financial condition and cash flows and our ability to meet long-term obligations, in the periods beyond twelve months from the date of this report, could be materially impacted. In connection with any sale or exiting of our generation plants as contemplated by the ESP settlement or otherwise, DPL and DP&L would expect to incur certain cash and non-cash charges, some or all of which could be material to the business and financial condition of DPL and DP&L . Regulatory assets and liabilities In accordance with FASC 980, we have recognized total regulatory assets of $204.0 million and $194.3 million at December 31, 2016 and 2015 , respectively, and total regulatory liabilities of $164.1 million and $151.4 million at December 31, 2016 and 2015 , respectively. Regulatory assets and liabilities are classified as current or non-current based on the term in which recovery is expected. See Note 1 – Overview and Summary of Significant Accounting Policies for accounting policies regarding Regulatory Assets and Liabilities. The following table presents DP&L’s Regulatory assets and liabilities: December 31, $ in millions Type of Recovery Amortization Through 2016 2015 Regulatory assets, current: Fuel and purchased power recovery costs A 2016 $ — $ 13.9 Economic development costs A 2017 0.1 0.5 Total regulatory assets, current 0.1 14.4 Regulatory assets, non-current: Pension benefits B Ongoing 97.6 91.6 Deferred recoverable income taxes B/C Ongoing 35.9 36.4 Unrecovered OVEC charges D Undetermined 21.0 10.5 Fuel costs B Undetermined 15.4 12.7 Unamortized loss on reacquired debt B Various 8.0 9.0 Smart grid and advanced metering infrastructure costs D Undetermined 7.3 7.3 Rate case costs D Undetermined 6.3 1.9 Generation separation costs D Undetermined 5.7 3.9 Retail settlement system costs D Undetermined 3.1 3.1 Consumer education campaign D Undetermined 3.0 3.0 Other miscellaneous D Undetermined 0.6 0.5 Total regulatory assets, non-current 203.9 179.9 Total regulatory assets $ 204.0 $ 194.3 Regulatory liabilities, current: Competitive bidding $ 16.1 $ 9.1 Energy efficiency program 14.1 9.2 Transmission costs 3.3 3.7 Reconciliation rider — 2.1 Other miscellaneous 0.2 0.3 Total regulatory liabilities, current 33.7 24.4 Regulatory liabilities, non-current: Estimated costs of removal - regulated property 126.5 121.8 Postretirement benefits 3.9 5.2 Total regulatory liabilities, non-current 130.4 127.0 Total regulatory liabilities $ 164.1 $ 151.4 A – Recovery of incurred costs plus rate of return. B – Recovery of incurred costs without a rate of return. C – Balance has an offsetting liability resulting in no effect on rate base. D – Recovery not yet determined, but is probable of occurring in future rate proceedings. Regulatory assets Fuel and purchased power recovery costs represent prudently incurred fuel, purchased power, derivative, emission and other related costs which will be recovered from or returned to customers in the future through the operation of the fuel and purchased power recovery rider. This rider was discontinued in 2016 and the remaining balance was transferred to the Competitive Bid True-up rider. Fuel costs - long term represent unrecovered fuel costs related to DP&L’s fuel rider from 2010 through 2015 resulting from a declining SSO customer base. DP&L has requested recovery of these costs as part of its pending Distribution Rate Case filing. Economic development costs represent costs incurred to promote economic development within the State of Ohio. These costs are being recovered through an Economic Development Rider that is subject to a bi-annual true-up process for any over/under recovery of costs. Pension benefits represent the qualifying FASC 715 “Compensation - Retirement Benefits” costs of our regulated operations that for ratemaking purposes are deferred for future recovery. We recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of OCI, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. This regulatory asset represents the regulated portion that would otherwise be charged as a loss to OCI. Deferred recoverable income taxes represent deferred income tax assets recognized from the normalization of flow-through items as the result of tax benefits previously provided to customers. This is the cumulative flow-through benefit given to regulated customers that will be collected from them in future years. Since currently existing temporary differences between the financial statements and the related tax basis of assets will reverse in subsequent periods, these deferred recoverable income taxes will decrease over time. Unrecovered OVEC charges includes the portion of charges from OVEC that were not recoverable through DP&L’s fuel rider beginning in October 2014. Because the fuel rider was discontinued in 2016, all OVEC costs, net of OVEC revenues received through PJM, are now deferred into this asset. DP&L expects to recover these costs through a future rate proceeding. Unamortized loss on reacquired debt represents losses on long-term debt reacquired or redeemed in prior periods that have been deferred. These deferred losses are being amortized over the lives of the original issues in accordance with FERC and PUCO rules. Smart Grid and AMI costs represent costs incurred as a result of studying and developing distribution system upgrades and the implementation of AMI. On October 19, 2010, DP&L elected to withdraw its case pertaining to the Smart Grid and AMI programs. The PUCO accepted the withdrawal in an order issued on January 5, 2011. The PUCO also indicated that it expects DP&L to continue to monitor other utilities' Smart Grid and AMI programs and to explore the potential benefits of investing in Smart Grid and AMI programs and that DP&L will, when appropriate, file new Smart Grid and/or AMI business cases in the future. This plan is currently under development and we plan to seek recover of these deferred costs in a regulatory rate proceeding in the near future. Based on past PUCO precedent, we believe these costs are probable of future recovery in rates. Rate case costs represent costs associated with preparing a distribution rate case. DP&L has requested recovery of these costs as part of its pending distribution rate case filing. Generation separation costs represent financing, redemption and other costs related to the divestiture of DP&L’s generation assets. The PUCO directed DP&L to divest its generation assets by January 1, 2017. DP&L requested and was granted permission by the PUCO to defer all financing, redemption and related costs it incurs to transfer its generation assets. DP&L has requested recovery of these costs as part of its pending distribution rate case filing. Retail settlement system costs represent costs to implement a retail settlement system that reconciles the energy a CRES supplier delivers to its customers with what its customers actually use. DP&L has requested recovery of these costs as part of its pending Distribution Rate Case filing. Consumer education campaign represents costs for consumer education advertising regarding electric deregulation. DP&L has requested recovery of these costs as part of its pending distribution rate case filing. Regulatory liabilities Competitive bidding represents costs associated with the development and implementation of a competitive bidding process, establishing contracts to supply power for DP&L’s SSO load, as well as the net over/under recovery of the cost of the power purchased from the bid winners. Energy efficiency program costs represent costs incurred to develop and implement various customer programs addressing energy efficiency. These costs are being recovered through an Energy Efficiency Rider (EER) that began July 1, 2009 and that is subject to an annual true-up for any over/under recovery of costs. In addition to recovery of program costs, this rider has allowed for DP&L to recover lost margin associated with decreases in sales as a result of the programs implemented. The authority to recover lost margin included a maximum amount, which DP&L reached in the fourth quarter of 2015. Consequently, we discontinued accruing an asset for lost revenues after the maximum was reached. On December 13, 2016 DP&L filed its Energy Efficiency portfolio case with the PUCO that specifies, among other things, that DP&L can collect lost distribution revenues for 2016 and going forward through the EER. The amount of lost revenues earned and accrued in 2016 is $20.1 million . Based on multiple parties’ agreement and past PUCO precedent on the treatment of lost distribution revenues for other utilities, it is probable, but not certain, DP&L will recover this amount. In addition, this rider provides that DP&L can earn a “shared savings” incentive that is tiered depending upon the level of success the programs reach. In 2015 and 2016, the maximum shared savings was accrued based upon performance, which is equal to $4.5 million after income taxes. Transmission costs represent the costs related to transmission, ancillary service and other PJM-related charges that have been incurred as a member of PJM. On an annual basis, retail rates are adjusted to true-up costs with recovery in rates. Reconciliation rider represents the costs that exceed 10 percent of the base amount of the following riders: Fuel, RPM, Alternative Energy and Competitive Bidding. This rider is in an overcollection position and will be discontinued after this overcollection has been refunded to customers. Estimated costs of removal – regulated property reflect an estimate of amounts collected in customer rates for costs that are expected to be incurred in the future to remove existing transmission and distribution property from service when the property is retired. Postretirement benefits represent the qualifying FASC 715 “Compensation – Retirement Benefits” gains related to our regulated operations that, for ratemaking purposes, are probable of being reflected in future rates. We recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of OCI, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. This regulatory liability represents the regulated portion that would otherwise be reflected as a gain to OCI. |
Property, Plant and Equipment
Property, Plant and Equipment | 12 Months Ended |
Dec. 31, 2016 | |
Property, Plant and Equipment [Line Items] | |
Property, Plant and Equipment | Property, Plant and Equipment The following is a summary of DPL’s Property, plant and equipment with corresponding composite depreciation rates at December 31, 2016 and 2015 : December 31, $ in millions 2016 Composite Rate 2015 Composite Rate Regulated: Transmission $ 247.3 3.9% $ 239.4 3.9% Distribution 1,141.1 4.7% 1,085.7 5.0% General 13.7 7.4% 13.9 7.2% Non-depreciable 63.5 N/A 62.5 N/A Total regulated 1,465.6 1,401.5 Unregulated: Production / Generation 483.2 11.7% 1,413.1 4.2% Other 17.0 8.0% 16.3 12.1% Non-depreciable 19.8 N/A 19.8 N/A Total unregulated 520.0 1,449.2 Total property, plant and equipment in service $ 1,985.6 6.1% $ 2,850.7 4.4% DP&L and certain other Ohio utilities have undivided ownership interests in five coal-fired electric generating facilities and numerous transmission facilities. Certain expenses, primarily fuel costs for the generating units, are allocated to the owners based on their energy usage. The remaining expenses, investments in fuel inventory, plant materials and operating supplies, and capital additions are allocated to the owners in accordance with their respective ownership interests. At December 31, 2016 , DP&L had $41.0 million of construction work in process at such facilities. DP&L’s share of the operations of such facilities is included within the corresponding line in the Statements of Operations, and DP&L’s share of the investment in the facilities is included within Total net property, plant and equipment in the Balance Sheets. Each joint owner provides their own financing for their share of the operations and capital expenditures of the jointly-owned station. Coal-fired facilities DP&L’s undivided ownership interest in such facilities at December 31, 2016 , is as follows: DP&L Share DPL Carrying Value Ownership (%) Summer Production Capacity (MW) Gross Plant In Service ($ in millions) Accumulated Depreciation ($ in millions) Construction Work in Process ($ in millions) Jointly-owned production units Conesville - Unit 4 16.5 129 $ — $ — $ — Killen - Unit 2 67.0 402 34 — 2 Miami Fort - Units 7 and 8 36.0 368 27 — 7 Stuart - Units 1 through 4 35.0 808 24 — 23 Zimmer - Unit 1 28.1 371 7 — 9 Transmission (at varying percentages) 43 10 — Total 2,078 $ 135 $ 10 $ 41 Each of the above generating units has SCR and FGD equipment installed. On January 10, 2017, a high pressure feedwater heater shell failed on Unit 1 at the J.M. Stuart station. As the damage assessment process is currently ongoing, we cannot determine the impact to operations or capacity at this time. AROs We recognize AROs in accordance with GAAP which requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time those obligations are incurred. Upon initial recognition of a legal liability, costs are capitalized as part of the related long-lived asset and depreciated over the useful life of the related asset. Our legal obligations are associated with the retirement of our long-lived assets, consisting primarily of river intake and discharge structures, coal unloading facilities, loading docks, ice breakers and ash disposal facilities. Our generation AROs are recorded within Other deferred credits on the consolidated balance sheets. Estimating the amount and timing of future expenditures of this type requires significant judgment. Management routinely updates these estimates as additional information becomes available. Changes in the Liability for Generation AROs $ in millions Balance at December 31, 2014 $ 26.9 Calendar 2015 Additions 40.3 Accretion expense 1.9 Settlements (3.2 ) Balance at December 31, 2015 65.9 Calendar 2016 Additions 70.2 Accretion expense 2.7 Settlements — Balance at December 31, 2016 $ 138.8 See Note 5 – Fair Value for further discussion on ARO additions. Asset Removal Costs We continue to record costs of removal for our regulated transmission and distribution assets through our depreciation rates and recover those amounts in rates charged to our customers. There are no known legal AROs associated with these assets. We have recorded $126.5 million and $121.8 million in estimated costs of removal at December 31, 2016 and 2015 , respectively, as regulatory liabilities for our transmission and distribution property. These amounts represent the excess of the cumulative removal costs recorded through depreciation rates versus the cumulative removal costs actually incurred. See Note 3 – Regulatory Matters for additional information. Changes in the Liability for Transmission and Distribution Asset Removal Costs $ in millions Balance at December 31, 2014 $ 119.3 Calendar 2015 Additions 24.3 Settlements (21.8 ) Balance at December 31, 2015 121.8 Calendar 2016 Additions 11.7 Settlements (7.0 ) Balance at December 31, 2016 $ 126.5 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Property, Plant and Equipment [Line Items] | |
Property, Plant and Equipment | Property, Plant and Equipment The following is a summary of DP&L’s Property, plant and equipment with corresponding composite depreciation rates at December 31, 2016 and 2015 : December 31, $ in millions 2016 Composite Rate 2015 Composite Rate Regulated: Transmission $ 421.1 2.3% $ 413.7 2.3% Distribution 1,693.5 3.2% 1,639.7 3.3% General 31.6 3.2% 31.6 3.2% Non-depreciable 63.5 N/A 62.5 N/A Total regulated 2,209.7 2,147.5 Unregulated: Production / Generation 173.9 26.2% 3,009.8 2.1% Non-depreciable 15.0 N/A 15.0 N/A Total unregulated 188.9 3,024.8 Total property, plant and equipment in service $ 2,398.6 4.6% $ 5,172.3 2.5% DP&L and certain other Ohio utilities have undivided ownership interests in five coal-fired electric generating facilities and numerous transmission facilities. Certain expenses, primarily fuel costs for the generating units, are allocated to the owners based on their energy usage. The remaining expenses, investments in fuel inventory, plant materials and operating supplies, and capital additions are allocated to the owners in accordance with their respective ownership interests. At December 31, 2016 , DP&L had $41.0 million of construction work in process at such facilities. DP&L’s share of the operations of such facilities is included within the corresponding line in the Statements of Operations, and DP&L’s share of the investment in the facilities is included within Total net property, plant and equipment in the Balance Sheets. Each joint owner provides their own financing for their share of the operations and capital expenditures of the jointly-owned station. Coal-fired facilities DP&L’s undivided ownership interest in such facilities at December 31, 2016 , is as follows: DP&L Share DP&L Carrying Value Ownership % Summer Production Capacity (MW) Gross Plant In Service ($ in millions) Accumulated Depreciation ($ in millions) Construction Work in Process ($ in millions) Jointly-owned production units Conesville - Unit 4 16.5 129 $ — $ — $ — Killen - Unit 2 67.0 402 34 — 2 Miami Fort - Units 7 and 8 36.0 368 27 — 7 Stuart - Units 1 through 4 35.0 808 24 — 23 Zimmer - Unit 1 28.1 371 7 — 9 Transmission (at varying percentages) 99 66 — Total 2,078 $ 191 $ 66 $ 41 Each of the above generating units has SCR and FGD equipment installed. On January 10, 2017, a high pressure feedwater heater shell failed on Unit 1 at the J.M. Stuart station. As the damage assessment process is currently ongoing, we cannot determine the impact to operations or capacity at this time. As part of the provisional DPL purchase accounting adjustments related to the Merger, four stations (Beckjord, Conesville, East Bend and Hutchings) had future expected cash flows that, when discounted, produced a fair market value different than DP&L’s carrying value. Since DP&L did not apply push down accounting, this valuation did not affect the carrying value of these stations’ valuation at DP&L . During 2016, DP&L performed an impairment review of its stations and recorded impairment expense of $1,353.5 million related to certain of its stations, including Conesville and Hutchings peaking facilities. See Note 14 – Fixed-asset Impairment for more information on these impairments. AROs We recognize AROs in accordance with GAAP which requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time those obligations are incurred. Upon initial recognition of a legal liability, costs are capitalized as part of the related long-lived asset and depreciated over the useful life of the related asset. Our legal obligations are associated with the retirement of our long-lived assets, consisting primarily of river intake and discharge structures, coal unloading facilities, loading docks, ice breakers and ash disposal facilities. Our generation AROs are recorded within Other deferred credits on the balance sheets. Estimating the amount and timing of future expenditures of this type requires significant judgment. Management routinely updates these estimates as additional information becomes available. Changes in the Liability for Generation AROs $ in millions Balance at December 31, 2014 $ 22.9 Calendar 2015 Additions 40.3 Accretion expense 2.1 Settlements (3.2 ) Balance at December 31, 2015 62.1 Calendar 2016 Additions 70.2 Accretion expense 2.9 Settlements — Balance at December 31, 2016 $ 135.2 See Note 5 – Fair Value for further discussion on current year ARO additions. Asset Removal Costs We continue to record costs of removal for our regulated transmission and distribution assets through our depreciation rates and recover those amounts in rates charged to our customers. There are no known legal AROs associated with these assets. We have recorded $126.5 million and $121.8 million in estimated costs of removal at December 31, 2016 and 2015 , respectively, as regulatory liabilities for our transmission and distribution property. These amounts represent the excess of the cumulative removal costs recorded through depreciation rates versus the cumulative removal costs actually incurred. See Note 3 – Regulatory Matters for additional information. Changes in the Liability for Transmission and Distribution Asset Removal Costs $ in millions Balance at December 31, 2014 $ 119.3 Calendar 2015 Additions 24.3 Settlements (21.8 ) Balance at December 31, 2015 121.8 Calendar 2016 Additions 11.7 Settlements (7.0 ) Balance at December 31, 2016 $ 126.5 |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2016 | |
Entity Information [Line Items] | |
Fair Value Measurements | Fair Value The fair values of our financial instruments are based on published sources for pricing when possible. We rely on valuation models only when no other method is available to us. The fair value of our financial instruments represents estimates of possible value that may or may not be realized in the future. The table below presents the fair value and cost of our non-derivative instruments at December 31, 2016 and 2015 . See Note 6 – Derivative Instruments and Hedging Activities for the fair values of our derivative instruments. December 31, 2016 December 31, 2015 $ in millions Cost Fair Value Cost Fair Value Assets Money market funds $ 0.4 $ 0.4 $ 0.2 $ 0.2 Equity securities 2.4 3.4 3.0 3.8 Debt securities 4.4 4.4 4.4 4.3 Hedge funds — 0.1 0.4 0.4 Real estate 0.3 0.3 0.3 0.3 Tangible assets 0.1 0.1 — — Total assets $ 7.6 $ 8.7 $ 8.3 $ 9.0 Carrying Value Fair Value Carrying Value Fair Value Liabilities Debt $ 1,858.4 $ 1,907.7 $ 1,993.3 $ 1,975.3 Fair value hierarchy Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. These inputs are then categorized as: • Level 1 (unadjusted quoted prices in active markets for identical assets or liabilities); • Level 2 (observable inputs such as quoted prices for similar assets or liabilities or quoted prices in markets that are not active); or • Level 3 (unobservable inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability). Valuations of assets and liabilities reflect the value of the instrument including the values associated with counterparty risk. We include our own credit risk and our counterparty’s credit risk in our calculation of fair value using global average default rates based on an annual study conducted by a large rating agency. We did not have any transfers of the fair values of our financial instruments between Level 1 and Level 2 of the fair value hierarchy during the twelve months ended December 31, 2016 and 2015 . Debt The fair value of debt is based on current public market prices for disclosure purposes only. Unrealized gains or losses are not recognized in the financial statements as debt is presented at the carrying value, net of unamortized premium or discount, in the financial statements. The debt amounts include the current portion payable in the next twelve months and have maturities that range from 2019 to 2061 . Master trust assets DP&L established a Master Trust to hold assets that could be used for the benefit of employees participating in employee benefit plans. These assets are primarily comprised of open-ended mutual funds, which are valued using the net asset value per unit. These investments are recorded at fair value within Other deferred assets on the balance sheets and classified as available for sale. Any unrealized gains or losses are recorded in AOCI until the securities are sold. DPL had $1.0 million ( $0.6 million after tax) in unrealized gains on the Master Trust assets in AOCI at December 31, 2016 , and $0.7 million ( $0.5 million after tax) in unrealized gains and immaterial unrealized losses in AOCI at December 31, 2015 . During the year ended December 31, 2016, $2.6 million ( $1.7 million after tax) of various investments were sold to facilitate the distribution of benefits. Over the next twelve months, an immaterial amount of unrealized gains is expected to be reversed to earnings. The fair value of assets and liabilities at December 31, 2016 and the respective category within the fair value hierarchy for DPL was determined as follows: Assets and Liabilities at Fair Value Level 1 Level 2 Level 3 $ in millions Fair Value at December 31, 2016 (a) Based on Quoted Prices in Active Markets Other observable inputs Unobservable inputs Assets Master trust assets Money market funds $ 0.4 $ 0.4 $ — $ — Equity securities 3.4 — 3.4 — Debt securities 4.4 — 4.4 — Hedge funds 0.1 — 0.1 — Real estate 0.3 — 0.3 — Tangible assets 0.1 — 0.1 — Total Master trust assets 8.7 0.4 8.3 — Derivative assets Forward power contracts 19.5 — 19.5 — Interest rate hedge 1.2 — 1.2 — FTRs 0.1 — — 0.1 Total Derivative assets 20.8 — 20.7 0.1 Total assets $ 29.5 $ 0.4 $ 29.0 $ 0.1 Liabilities FTRs $ — $ — $ — $ — Interest rate hedge 0.7 — 0.7 — Forward power contracts 28.5 — 26.0 2.5 Total derivative liabilities 29.2 — 26.7 2.5 Long-term debt 1,907.7 — 1,889.7 18.0 Total liabilities $ 1,936.9 $ — $ 1,916.4 $ 20.5 (a) Includes credit valuation adjustment. The fair value of assets and liabilities at December 31, 2015 and the respective category within the fair value hierarchy for DPL was determined as follows: Assets and Liabilities at Fair Value Level 1 Level 2 Level 3 $ in millions Fair Value at December 31, 2015 (a) Based on Quoted Prices in Active Markets Other observable inputs Unobservable inputs Assets Master trust assets Money market funds $ 0.2 $ 0.2 $ — $ — Equity securities 3.8 — 3.8 — Debt securities 4.3 — 4.3 — Hedge funds 0.4 — 0.4 — Real estate 0.3 — 0.3 — Total Master trust assets 9.0 0.2 8.8 — Derivative assets Forward power contracts 30.5 — 30.5 — FTRs 0.2 — — 0.2 Total derivative assets 30.7 — 30.5 0.2 Total assets $ 39.7 $ 0.2 $ 39.3 $ 0.2 Liabilities FTRs $ 0.5 $ — $ — $ 0.5 Forward power contracts 27.0 — 23.9 3.1 Total derivative liabilities 27.5 — 23.9 3.6 Long-term debt 1,975.3 — 1,957.2 18.1 Total liabilities $ 2,002.8 $ — $ 1,981.1 $ 21.7 (a) Includes credit valuation adjustment. Our financial instruments are valued using the market approach in the following categories: • Level 1 inputs are used for derivative contracts, such as heating oil futures, and for money market accounts that are considered cash equivalents. The fair value is determined by reference to quoted market prices and other relevant information generated by market transactions. • Level 2 inputs are used to value derivatives such as forward power contracts (which are traded on the OTC market but which are valued using prices on the NYMEX for similar contracts on the OTC market). Other Level 2 assets include: open-ended mutual funds that are in the Master Trust, which are valued using the end of day NAV per unit. • Level 3 inputs, such as financial transmission rights, are considered a Level 3 input because the monthly auctions are considered inactive. Our Level 3 inputs are immaterial to our derivative balances as a whole and as such no further disclosures are presented. Our debt is fair valued for disclosure purposes only and most of the fair values are determined using quoted market prices in inactive markets. These fair value inputs are considered Level 2 in the fair value hierarchy. The WPAFB note is not publicly traded. Fair value is assumed to equal carrying value. These fair value inputs are considered Level 3 in the fair value hierarchy as there are no observable inputs. Additional Level 3 disclosures were not presented since debt is not recorded at fair value. Approximately 94.7% of the inputs to the fair value of our derivative instruments are from quoted market prices. Non-recurring Fair Value Measurements We use the cost approach to determine the fair value of our AROs, which are estimated by discounting expected cash outflows to their present value at the initial recording of the liability. Cash outflows are based on the approximate future disposal cost as determined by market information, historical information or other management estimates. These inputs to the fair value of the AROs would be considered Level 3 inputs under the fair value hierarchy. AROs for asbestos, ash ponds, underground storage tanks, and river structures increased by a net amount of $72.9 million ( $47.4 million after tax) and $39.0 million ( $25.4 million after tax) during the years ended December 31, 2016 and 2015 , respectively. Increases to the AROs for the Stuart and Killen Plants totaling $67.9 million ( $44.1 million after tax) were recorded in 2016 to reflect revised estimated closure expenditures as well as plant closure dates that are earlier than previously forecast. Smaller changes were also recorded to the AROs for certain other plants to reflect changes in estimated closure costs. The majority of the increase for 2015 is due to a net increase in the ARO for ash ponds of $40.3 million ( $26.2 million after tax) as a result of new rules promulgated by the USEPA that were published in the Federal Register in April 2015 and became effective in October 2015. See Note 4 – Property, Plant and Equipment for more information about AROs. When evaluating impairment of goodwill and long-lived assets, we measure fair value using the applicable fair value measurement guidance. Impairment expense is measured by comparing the fair value at the evaluation date to the carrying amount. The following table summarizes major categories of assets and liabilities measured at fair value on a nonrecurring basis during the period and their level within the fair value hierarchy: Measurement Carrying Fair Value Gross $ in millions Date Amount Level 1 Level 2 Level 3 Loss Long-lived assets (a) Year ended December 31, 2016 Killen December 31, 2016 $ 118.2 $ — $ — $ 42.8 $ 75.4 Stuart December 31, 2016 $ 285.9 $ — $ — $ 57.4 228.5 Miami Fort December 31, 2016 $ 185.9 $ — $ — $ 36.5 149.4 Zimmer December 31, 2016 $ 168.4 $ — $ — $ 23.7 144.7 Conesville December 31, 2016 $ 25.0 $ — $ — $ 1.1 23.9 Hutchings peaking facilities December 31, 2016 $ 3.2 $ — $ — $ 1.6 1.6 Killen June 30, 2016 $ 315.1 $ — $ — $ 84.3 230.8 Certain peaking facilities June 30, 2016 $ 9.9 $ — $ — $ 5.2 4.7 Total impairment loss $ 859.0 Year ended December 31, 2014 East Bend March 31, 2014 $ 14.2 $ — $ — $ 2.7 $ 11.5 Goodwill (b) Year ended December 31, 2015 DP&L reporting unit December 31, 2015 $ 317.0 $ — $ — $ — $ 317.0 Year ended December 31, 2014 DPLER Reporting unit June 30, 2014 $ 135.8 $ — $ — $ — $ 135.8 (a) See Note 15 – Fixed-asset Impairment for further information (b) See Note 7 – Goodwill for further information The following summarizes the significant unobservable inputs used in the Level 3 measurement on a non-recurring basis during the year ended December 31, 2016: $ in millions Measurement date Fair value Valuation technique Unobservable input Range (weighted average) Long-lived assets held and used: Year ended December 31, 2016 Killen December 31, 2016 $ 42.8 Discounted cash flow Annual revenue growth -14.2% to 2.9% (-8.0%) Annual pre-tax operating margin -56.6% to 42.4% (-15.5%) Weighted-average cost of capital 10.0% Stuart December 31, 2016 $ 57.4 Discounted cash flow Annual revenue growth -11.9% to 1.1% (-4.7%) Annual pre-tax operating margin -61.4% to 75.1% (8.0%) Weighted-average cost of capital 10.0% Miami Fort December 31, 2016 $ 36.5 Market value Indicative offer price Zimmer December 31, 2016 $ 23.7 Market value Indicative offer price Conesville December 31, 2016 $ 1.1 Discounted cash flow Annual revenue growth -19.3% to 10.9% (0.6%) Annual pre-tax operating margin -54.3% to 99.4% (20.2%) Weighted-average cost of capital N/A Hutchings peaking facilities December 31, 2016 $ 1.6 Discounted cash flow Annual revenue growth -19.5% to 25.9% (-0.7%) Annual pre-tax operating margin -40.3% to 63.1% (12.1%) Weighted-average cost of capital 7.0% Killen June 30, 2016 $ 84.3 Discounted cash flow Annual revenue growth -11.0% to 13.0% (2.0%) Annual pre-tax operating margin -50.0% to 67.0% (6.0%) Weighted-average cost of capital 11.0% Certain peaking facilities June 30, 2016 $ 5.2 Discounted cash flow Annual revenue growth -22.0% to 17.0% (-3.0%) Annual pre-tax operating margin -29.0% to 24.0% (-4.0%) Weighted-average cost of capital 7.0% |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Entity Information [Line Items] | |
Fair Value Measurements | Fair Value The fair values of our financial instruments are based on published sources for pricing when possible. We rely on valuation models only when no other method is available to us. The fair value of our financial instruments represents estimates of possible value that may or may not be realized in the future. The table below presents the fair value and cost of our non-derivative instruments at December 31, 2016 and 2015 . See also Note 6 – Derivative Instruments and Hedging Activities for the fair values of our derivative instruments. December 31, 2016 December 31, 2015 $ in millions Cost Fair Value Cost Fair Value Assets Money market funds $ 0.4 $ 0.4 $ 0.2 $ 0.2 Equity securities 2.4 3.4 3.0 3.8 Debt securities 4.4 4.4 4.4 4.3 Hedge funds — 0.1 0.4 0.4 Real estate 0.3 0.3 0.3 0.3 Tangible assets 0.1 0.1 — — Total assets $ 7.6 $ 8.7 $ 8.3 $ 9.0 Carrying Value Fair Value Carrying Value Fair Value Liabilities Debt $ 749.4 $ 763.5 $ 756.7 $ 764.2 Fair value hierarchy Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. These inputs are then categorized as: • Level 1 (unadjusted quoted prices in active markets for identical assets or liabilities); • Level 2 (observable inputs such as quoted prices for similar assets or liabilities or quoted prices in markets that are not active); or • Level 3 (unobservable inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability). Valuations of assets and liabilities reflect the value of the instrument including the values associated with counterparty risk. We include our own credit risk and our counterparty’s credit risk in our calculation of fair value using global average default rates based on an annual study conducted by a large rating agency. We did not have any transfers of the fair values of our financial instruments between Level 1 and Level 2 of the fair value hierarchy during the twelve months ended December 31, 2016 and 2015 . Debt The fair value of debt is based on current public market prices for disclosure purposes only. Unrealized gains or losses are not recognized in the financial statements as debt is presented at the carrying value, net of unamortized premium or discount, in the financial statements. The debt amounts include the current portion payable in the next twelve months and have maturities that range from 2020 to 2061 . Master trust assets DP&L established a Master Trust to hold assets that could be used for the benefit of employees participating in employee benefit plans. These assets are primarily comprised of open-ended mutual funds, which are valued using the net asset value per unit. These investments are recorded at fair value within Other deferred assets on the balance sheets and classified as available for sale. Any unrealized gains or losses are recorded in AOCI until the securities are sold. DP&L had $1.1 million ( $0.7 million after tax) in unrealized gains on the Master Trust assets in AOCI at December 31, 2016 and $0.8 million ( $0.5 million after tax) in unrealized gains and immaterial unrealized losses in AOCI at December 31, 2015 . During the year ended December 31, 2016, $2.6 million ( $1.7 million after tax) of various investments were sold to facilitate the distribution of benefits. Over the next twelve months, an immaterial amount of unrealized gains is expected to be reversed to earnings. The fair value of assets and liabilities at December 31, 2016 and the respective category within the fair value hierarchy for DP&L was determined as follows: Assets and Liabilities at Fair Value Level 1 Level 2 Level 3 $ in millions Fair Value at December 31, 2016 (a) Based on Quoted Prices in Active Markets Other observable inputs Unobservable inputs Assets Master trust assets Money market funds $ 0.4 $ 0.4 $ — $ — Equity securities 3.4 — 3.4 — Debt securities 4.4 — 4.4 — Hedge funds 0.1 — 0.1 — Real estate 0.3 — 0.3 — Tangible assets 0.1 — 0.1 — Total Master trust assets 8.7 0.4 8.3 — Derivative assets FTRs 0.1 — — 0.1 Interest rate hedge 1.2 — 1.2 — Forward power contracts 19.5 — 19.5 — Total derivative assets 20.8 — 20.7 0.1 Total assets $ 29.5 $ 0.4 $ 29.0 $ 0.1 Liabilities FTRs $ — $ — $ — $ — Interest rate hedge 0.7 — 0.7 — Forward power contracts 28.5 — 26.0 2.5 Total derivative liabilities 29.2 — 26.7 2.5 Long-term debt 763.5 — 745.5 18.0 Total liabilities $ 792.7 $ — $ 772.2 $ 20.5 (a) Includes credit valuation adjustment. The fair value of assets and liabilities at December 31, 2015 and the respective category within the fair value hierarchy for DP&L was determined as follows: Assets and Liabilities at Fair Value Level 1 Level 2 Level 3 $ in millions Fair Value at December 31, 2015 (a) Based on Quoted Prices in Active Markets Other observable inputs Unobservable inputs Assets Master trust assets Money market funds $ 0.2 $ 0.2 $ — $ — Equity securities 3.8 — 3.8 — Debt securities 4.3 — 4.3 — Hedge funds 0.4 — 0.4 — Real estate 0.3 — 0.3 — Total Master trust assets 9.0 0.2 8.8 — Derivative assets FTRs 0.2 — — 0.2 Forward power contracts 30.6 — 30.6 — Total derivative assets 30.8 — 30.6 0.2 Total assets $ 39.8 $ 0.2 $ 39.4 $ 0.2 Liabilities FTRs $ 0.5 $ — $ — $ 0.5 Forward power contracts 27.0 — 23.9 3.1 Total derivative liabilities 27.5 — 23.9 3.6 Long-term debt 764.2 — 746.1 18.1 Total liabilities $ 791.7 $ — $ 770.0 $ 21.7 (a) Includes credit valuation adjustment. Our financial instruments are valued using the market approach in the following categories: • Level 1 inputs are used for derivative contracts, such as heating oil futures, and for money market accounts that are considered cash equivalents. The fair value is determined by reference to quoted market prices and other relevant information generated by market transactions. • Level 2 inputs are used to value derivatives such as forward power contracts (which are traded on the OTC market but which are valued using prices on the NYMEX for similar contracts on the OTC market). Other Level 2 assets include: open-ended mutual funds that are in the Master Trust, which are valued using the end of day NAV per unit. • Level 3 inputs, such as financial transmission rights, are considered a Level 3 input because the monthly auctions are considered inactive. Our Level 3 inputs are immaterial to our derivative balances as a whole and as such no further disclosures are presented. Our debt is fair valued for disclosure purposes only and most of the fair values are determined using quoted market prices in inactive markets. These fair value inputs are considered Level 2 in the fair value hierarchy. The WPAFB note is not publicly traded. Fair value is assumed to equal carrying value. These fair value inputs are considered Level 3 in the fair value hierarchy as there are no observable inputs. Additional Level 3 disclosures were not presented since debt is not recorded at fair value. Approximately 94.7% of the inputs to the fair value of our derivative instruments are from quoted market prices. Non-recurring Fair Value Measurements We use the cost approach to determine the fair value of our AROs, which are estimated by discounting expected cash outflows to their present value at the initial recording of the liability. Cash outflows are based on the approximate future disposal cost as determined by market information, historical information or other management estimates. These inputs to the fair value of the AROs would be considered Level 3 inputs under the fair value hierarchy. AROs for asbestos, ash ponds, underground storage tanks, and river structures increased by a net amount of $73.1 million ( $47.5 million after tax) and $39.2 million ( $25.5 million after tax) during the years ended December 31, 2016 and 2015 , respectively. Increases to the AROs for the Stuart and Killen Plants totaling $67.9 million ( $44.1 million after tax) were recorded in 2016 to reflect revised estimated closure expenditures as well as plant closure dates that are earlier than previously forecast. Smaller changes were also recorded to the AROs for certain other plants to reflect changes in estimated closure costs. The majority of the increase for 2015 is due to a net increase in the ARO for ash ponds of $40.3 million ( $26.2 million after tax) as a result of new rules promulgated by the USEPA that were published in the Federal Register in April 2015 and became effective in October 2015. See Note 4 – Property, Plant and Equipment for more information about AROs. When evaluating impairment of long-lived assets, we measure fair value using the applicable fair value measurement guidance. Impairment expense is measured by comparing the fair value at the evaluation date to the carrying amount. The following table summarizes major categories of assets and liabilities measured at fair value on a nonrecurring basis during the period and their level within the fair value hierarchy: Measurement Carrying Fair Value Gross $ in millions Date Amount Level 1 Level 2 Level 3 Loss Long-lived assets (a) Year ended December 31, 2016 Killen December 31, 2016 $ 118.1 $ — $ — $ 42.8 $ 75.3 Stuart December 31, 2016 $ 207.3 $ — $ — $ 57.4 149.9 Miami Fort December 31, 2016 $ 194.2 $ — $ — $ 36.5 157.7 Zimmer December 31, 2016 $ 115.0 $ — $ — $ 23.7 91.3 Conesville December 31, 2016 $ 21.9 $ — $ — $ 1.1 20.8 Hutchings peaking facilities December 31, 2016 $ 3.0 $ — $ — $ 1.6 1.4 Stuart June 30, 2016 $ 456.4 $ — $ — $ 164.4 292.0 Killen June 30, 2016 $ 330.5 $ — $ — $ 84.3 246.2 Zimmer June 30, 2016 $ 429.9 $ — $ — $ 111.0 318.9 Total impairment loss $ 1,353.5 (a) See Note 14 – Fixed-asset Impairment for further information. The following summarizes the significant unobservable inputs used in the Level 3 measurement on a non-recurring basis during the year ended December 31, 2016: $ in millions Measurement date Fair value Valuation technique Unobservable input Range (weighted average) Long-lived assets held and used: Year ended December 31, 2016 Killen December 31, 2016 $ 42.8 Discounted cash flow Annual revenue growth -14.2% to 2.9% (-8.0%) Annual pre-tax operating margin -56.6% to 42.4% (-15.5%) Weighted-average cost of capital 10.0% $ in millions Measurement date Fair value Valuation technique Unobservable input Range (weighted average) Long-lived assets held and used: Year ended December 31, 2016 Stuart December 31, 2016 $ 57.4 Discounted cash flow Annual revenue growth -11.9% to 1.1% (-4.7%) Annual pre-tax operating margin -61.4% to 75.1% (8.0%) Weighted-average cost of capital 10.0% Miami Fort December 31, 2016 $ 36.5 Market value Indicative offer price Zimmer December 31, 2016 $ 23.7 Market value Indicative offer price Conesville December 31, 2016 $ 1.1 Discounted cash flow Annual revenue growth -19.3% to 10.9% (0.6%) Annual pre-tax operating margin -54.3% to 99.4% (20.2%) Weighted-average cost of capital N/A Hutchings peaking facilities December 31, 2016 $ 1.6 Discounted cash flow Annual revenue growth -19.5% to 25.9% (-0.7%) Annual pre-tax operating margin -40.3% to 63.1% (12.1%) Weighted-average cost of capital 7.0% Stuart June 30, 2016 $ 164.4 Discounted cash flow Annual revenue growth -9.0% to 10.0% (2.0%) Annual pre-tax operating margin -29.0% to 52.0% (5.0%) Weighted-average cost of capital 9.0% Killen June 30, 2016 $ 84.3 Discounted cash flow Annual revenue growth -11.0% to 13.0% (2.0%) Annual pre-tax operating margin -50.0% to 67.0% (6.0%) Weighted-average cost of capital 11.0% Zimmer June 30, 2016 $ 111.0 Discounted cash flow Annual revenue growth -14.0% to 13.0% (1.0%) Annual pre-tax operating margin -46.0% to 80.0% (4.0%) Weighted-average cost of capital 9.0% |
Derivative Instruments and Hedg
Derivative Instruments and Hedging Activities | 12 Months Ended |
Dec. 31, 2016 | |
Derivative Instruments and Hedging Activities | Derivative Instruments and Hedging Activities In the normal course of business, DPL enters into various financial instruments, including derivative financial instruments. We use derivatives principally to manage the risk of changes in market prices for commodities and interest rate risk associated with our long-term debt. The derivatives that we use to economically hedge these risks are governed by our risk management policies for forward and futures contracts. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The objective of the hedging program is to mitigate financial risks while ensuring that we have adequate resources to meet our requirements. We monitor and value derivative positions monthly as part of our risk management processes. We use published sources for pricing, when possible, to mark positions to market. All of our derivative instruments are used for risk management purposes and are designated as cash flow hedges if they qualify under FASC 815 for accounting purposes. At December 31, 2016 , DPL had the following outstanding derivative instruments: Commodity Accounting Treatment Unit Purchases (in thousands) Sales (in thousands) Net Purchases/ (Sales) (in thousands) FTRs Not designated MWh 2.3 — 2.3 Natural Gas Not designated Dths 1,590.0 — 1,590.0 Forward Power Contracts Designated MWh 342.9 (9,974.5 ) (9,631.6 ) Forward Power Contracts Not designated MWh 2,568.3 (2,020.9 ) 547.4 Interest Rate Swaps Designated USD 200,000.0 — 200,000.0 At December 31, 2015 , DPL had the following outstanding derivative instruments: Commodity Accounting Treatment Unit Purchases (in thousands) Sales (in thousands) Net Purchases/ (Sales) (in thousands) FTRs Not designated MWh 10.2 — 10.2 Forward Power Contracts Designated MWh 1,676.7 (7,795.8 ) (6,119.1 ) Forward Power Contracts Not designated MWh 5,049.9 (1,663.0 ) 3,386.9 Cash flow hedges As part of our risk management processes, we identify the relationships between hedging instruments and hedged items, as well as the risk management objective and strategy for undertaking various hedge transactions. The fair values of cash flow hedges determined by current public market prices will continue to fluctuate with changes in market prices up to contract expiration. The effective portion of the hedging transaction is recognized in AOCI and transferred to earnings using specific identification of each contract when the forecasted hedged transaction takes place or when the forecasted hedged transaction is probable of not occurring. The ineffective portion of the cash flow hedge is recognized in earnings in the current period. All risk components were taken into account to determine the hedge effectiveness of the cash flow hedges. We enter into forward power contracts to manage commodity price risk exposure related to our generation of electricity. We do not hedge all commodity price risk. We reclassify gains and losses on forward power contracts from AOCI into earnings in those periods in which the contracts settle. In November 2016, we entered into two interest rate swaps to hedge the variable interest on our $200.0 million variable interest rate tax-exempt First Mortgage Bonds. The interest rate swaps have a combined notional amount of $200.0 million and will settle monthly based on a one month LIBOR. We use the income approach to value the swaps, which consists of forecasting future cash flows based on contractual notional amounts and applicable and available market data as of the valuation date. The most common market data inputs used in the income approach include volatilities, spot and forward benchmark interest rates (LIBOR). Forward rates with the same tenor as the derivative instrument being valued are generally obtained from published sources, with these forward rates being assessed quarterly at a portfolio-level for reasonableness versus comparable published rates. We reclassify gains and losses on the swaps out of AOCI and into earnings in those periods in which hedged interest payments occur. The following tables set forth the gains / (losses) recognized in AOCI and earnings related to the effective portion of derivative instruments and the gains / (losses) recognized in earnings related to the ineffective portion of derivative instruments in qualifying cash flow hedging relationships, as defined in the accounting standards for derivatives and hedging, for the periods indicated: Years ended December 31, 2016 2015 2014 $ in millions (net of tax) Power Interest Rate Hedges Power Interest Rate Hedges Power Interest Rate Hedges Beginning accumulated derivative gain in AOCI $ 9.2 $ 17.5 $ 0.2 $ 18.3 $ 1.4 $ 19.2 Net gains / (losses) associated with current period hedging transactions 15.7 0.4 18.2 — (19.0 ) — Net gains / (losses) reclassified to earnings: Interest Expense — (0.5 ) — (0.8 ) — (0.9 ) Revenues (35.6 ) — (12.0 ) — 18.3 — Purchased Power 6.4 — 2.8 — (0.5 ) — Ending accumulated derivative gain / (loss) in AOCI $ (4.3 ) $ 17.4 $ 9.2 $ 17.5 $ 0.2 $ 18.3 Net gains or losses associated with the ineffective portion of the hedging transactions were immaterial in the periods presented. Portion expected to be reclassified to earnings in the next twelve months (a) $ (3.5 ) $ (0.5 ) Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) 15 44 (a) The actual amounts that we reclassify from AOCI to earnings related to power can differ from the estimate above due to market price changes. Derivatives not designated as hedges Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for hedge accounting or the normal purchases and sales exceptions under FASC 815. Accordingly, such contracts are recorded at fair value with changes in the fair value charged or credited to the consolidated statements of operations in the period in which the change occurred. This is commonly referred to as “MTM accounting”. Contracts we enter into as part of our risk management program may be settled financially, by physical delivery or net settled with the counterparty. We mark to market FTRs, natural gas futures and certain forward power contracts. Certain qualifying derivative instruments have been designated as normal purchases or normal sales contracts, as provided under GAAP. Derivative contracts that have been designated as normal purchases or normal sales under GAAP are not subject to MTM accounting treatment and are recognized in the consolidated statements of operations on an accrual basis. Regulatory assets and liabilities In accordance with regulatory accounting under GAAP, a cost that is probable of recovery in future rates should be deferred as a regulatory asset and a gain that is probable of being returned to customers should be deferred as a regulatory liability. Portions of the derivative contracts that are marked to market each reporting period and are related to the retail portion of DP&L’s load requirements are included as part of the fuel and purchased power recovery rider approved by the PUCO which began January 1, 2010. Therefore, the Ohio retail customers’ portion of the heating oil futures are deferred as a regulatory asset or liability until the contracts settle. If these unrealized gains and losses are no longer deemed to be probable of recovery through our rates, they will be reclassified into earnings in the period such determination is made. The following tables show the amount and classification within the consolidated statements of operations or balance sheets of the gains and losses on DPL’s derivatives not designated as hedging instruments for the years ended December 31, 2016 , 2015 and 2014 : Year ended December 31, 2016 $ in millions Heating Oil FTRs Power Natural Gas Total Derivatives not designated as hedging instruments Change in unrealized gain / (loss) $ — $ 0.3 $ 4.0 $ — $ 4.3 Realized gain / (loss) — (0.6 ) (7.2 ) 2.6 (5.2 ) Total $ — $ (0.3 ) $ (3.2 ) $ 2.6 $ (0.9 ) Recorded on Balance Sheet: Regulatory asset $ — $ — $ — $ — $ — Recorded in Statement of Operations: gain / (loss) Revenue — — (17.3 ) — (17.3 ) Purchased Power — (0.3 ) 14.1 2.6 16.4 Total $ — $ (0.3 ) $ (3.2 ) $ 2.6 $ (0.9 ) Year ended December 31, 2015 $ in millions Heating Oil FTRs Power Natural Gas Total Derivatives not designated as hedging instruments Change in unrealized gain / (loss) $ 0.4 $ 0.3 $ (6.4 ) $ 0.1 $ (5.6 ) Realized gain / (loss) (0.3 ) (0.2 ) (9.8 ) (0.1 ) (10.4 ) Total $ 0.1 $ 0.1 $ (16.2 ) $ — $ (16.0 ) Recorded on Balance Sheet: Regulatory asset $ 0.1 $ — $ — $ — $ 0.1 Recorded in Statement of Operations: gain / (loss) Revenue — — 27.4 — 27.4 Purchased Power — 0.1 (43.6 ) — (43.5 ) Total $ 0.1 $ 0.1 $ (16.2 ) $ — $ (16.0 ) Year ended December 31, 2014 $ in millions Heating Oil FTRs Power Natural Gas Total Derivatives not designated as hedging instruments Change in unrealized gain / (loss) $ (0.6 ) $ (0.8 ) $ (1.5 ) $ (0.1 ) $ (3.0 ) Realized gain / (loss) (0.1 ) 0.7 (3.6 ) (0.1 ) (3.1 ) Total $ (0.7 ) $ (0.1 ) $ (5.1 ) $ (0.2 ) $ (6.1 ) Recorded on Balance Sheet Regulatory asset $ (0.1 ) $ — $ — $ — $ (0.1 ) Recorded in Statement of Operations: gain / (loss) Fuel (0.6 ) — — — (0.6 ) Purchased Power — (0.1 ) (5.1 ) (0.2 ) (5.4 ) Total $ (0.7 ) $ (0.1 ) $ (5.1 ) $ (0.2 ) $ (6.1 ) The following tables show the fair value, balance sheet classification and hedging designation of DPL’s derivative instruments at December 31, 2016 and 2015 . Fair Values of Derivative Instruments December 31, 2016 Gross Amounts Not Offset in the Consolidated Balance Sheets $ in millions Hedging Designation Gross Fair Value as presented in the Consolidated Balance Sheets (a) Financial Instruments with Same Counterparty in Offsetting Position Cash Collateral Net Amount Assets Short-term derivative positions (presented in Other current assets) Forward power contracts Designated $ 11.0 $ (10.5 ) $ — $ 0.5 Forward power contracts Not designated 6.0 (4.7 ) — 1.3 FTRs Not designated 0.1 — — 0.1 Long-term derivative positions (presented in Other deferred assets) Interest Rate Swaps Designated 1.2 — — 1.2 Forward power contracts Designated 0.6 (0.6 ) — — Forward power contracts Not designated 1.9 (1.0 ) — 0.9 Total assets $ 20.8 $ (16.8 ) $ — $ 4.0 Liabilities Short-term derivative positions (presented in Other current liabilities) Interest Rate Swaps Designated $ 0.7 $ — $ — $ 0.7 Forward power contracts Designated $ 16.4 $ (10.5 ) $ (5.5 ) $ 0.4 Forward power contracts Not designated 7.7 (4.7 ) — 3.0 FTRs Not designated — — — — Long-term derivative positions (presented in Other deferred liabilities) Forward power contracts Designated 2.4 (0.6 ) (0.8 ) 1.0 Forward power contracts Not designated 2.0 (1.0 ) — 1.0 Total liabilities $ 29.2 $ (16.8 ) $ (6.3 ) $ 6.1 (a) Includes credit valuation adjustment. Fair Values of Derivative Instruments December 31, 2015 Gross Amounts Not Offset in the Consolidated Balance Sheets $ in millions Hedging Designation Gross Fair Value as presented in the Consolidated Balance Sheets (a) Financial Instruments with Same Counterparty in Offsetting Position Cash Collateral Net Amount Assets Short-term derivative positions (presented in Other current assets) Forward power contracts Designated $ 16.2 $ (7.1 ) $ — $ 9.1 Forward power contracts Not designated 7.3 (5.5 ) — 1.8 FTRs Not designated 0.2 (0.2 ) — — Long-term derivative positions (presented in Other deferred assets) Forward power contracts Designated 3.0 (2.4 ) — 0.6 Forward power contracts Not designated 4.0 (2.7 ) — 1.3 Total assets $ 30.7 $ (17.9 ) $ — $ 12.8 Liabilities Short-term derivative positions (presented in Other current liabilities) Forward power contracts Designated $ 7.1 $ (7.1 ) $ — $ — Forward power contracts Not designated 14.5 (5.5 ) (8.0 ) 1.0 FTRs Not designated 0.5 (0.2 ) — 0.3 Long-term derivative positions (presented in Other deferred liabilities) Forward power contracts Designated 2.7 (2.4 ) — 0.3 Forward power contracts Not designated 2.7 (2.7 ) — — Total liabilities $ 27.5 $ (17.9 ) $ (8.0 ) $ 1.6 (a) Includes credit valuation adjustment. Credit risk-related contingent features Certain of our OTC commodity derivative contracts are under master netting agreements that contain provisions that require our debt to maintain an investment grade credit rating from credit rating agencies. Since our debt has fallen below investment grade, we are in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization of the MTM loss. Some of our counterparties to the derivative instruments have requested collateralization of the MTM loss. The aggregate fair value of DPL’s derivative instruments that are in a MTM loss position at December 31, 2016 is $29.2 million . This amount is offset by $6.3 million of collateral posted directly with third parties and in a broker margin account which offsets our loss positions on the forward contracts. This liability position is further offset by the asset position of counterparties with master netting agreements of $16.8 million . Since our debt is below investment grade, we could have to post collateral for the remaining $6.1 million . |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Derivative Instruments and Hedging Activities | Derivative Instruments and Hedging Activities In the normal course of business, DP&L enters into various financial instruments, including derivative financial instruments. We use derivatives principally to manage the risk of changes in market prices for commodities and interest rate risk associated with our long-term debt. The derivatives that we use to economically hedge these risks are governed by our risk management policies for forward and futures contracts. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The objective of the hedging program is to mitigate financial risks while ensuring that we have adequate resources to meet our requirements. We monitor and value derivative positions monthly as part of our risk management processes. We use published sources for pricing, when possible, to mark positions to market. All of our derivative instruments are used for risk management purposes and are designated as cash flow hedges if they qualify under FASC 815 for accounting purposes. At December 31, 2016 , DP&L had the following outstanding derivative instruments: Commodity Accounting Treatment Unit Purchases (in thousands) Sales (in thousands) Net Purchases/ (Sales) (in thousands) FTRs Not designated MWh 2.3 — 2.3 Natural Gas Not designated Dths 1,590.0 — 1,590.0 Forward Power Contracts Designated MWh 342.9 (9,974.5 ) (9,631.6 ) Forward Power Contracts Not designated MWh 2,568.3 (2,037.5 ) 530.8 Interest Rate Swaps Designated USD 200,000.0 — 200,000.0 At December 31, 2015 , DP&L had the following outstanding derivative instruments: Commodity Accounting Treatment Unit Purchases (in thousands) Sales (in thousands) Net Purchases/ (Sales) (in thousands) FTRs Not designated MWh 10.2 — 10.2 Forward Power Contracts Designated MWh 1,676.7 (7,795.8 ) (6,119.1 ) Forward Power Contracts Not designated MWh 5,049.9 (1,665.7 ) 3,384.2 Cash flow hedges As part of our risk management processes, we identify the relationships between hedging instruments and hedged items, as well as the risk management objective and strategy for undertaking various hedge transactions. The fair values of cash flow hedges determined by current public market prices will continue to fluctuate with changes in market prices up to contract expiration. The effective portion of the hedging transaction is recognized in AOCI and transferred to earnings using specific identification of each contract when the forecasted hedged transaction takes place or when the forecasted hedged transaction is probable of not occurring. The ineffective portion of the cash flow hedge is recognized in earnings in the current period. All risk components were taken into account to determine the hedge effectiveness of the cash flow hedges. We enter into forward power contracts to manage commodity price risk exposure related to our generation of electricity. We do not hedge all commodity price risk. We reclassify gains and losses on forward power contracts from AOCI into earnings in those periods in which the contracts settle. In November 2016, we entered into two interest rate swaps to hedge the variable interest on our $200.0 million variable interest rate tax-exempt First Mortgage Bonds. The interest rate swaps have a combined notional amount of $200.0 million and will settle monthly based on a one month LIBOR. We use the income approach to value the swaps, which consists of forecasting future cash flows based on contractual notional amounts and applicable and available market data as of the valuation date. The most common market data inputs used in the income approach include volatilities, spot and forward benchmark interest rates (LIBOR). Forward rates with the same tenor as the derivative instrument being valued are generally obtained from published sources, with these forward rates being assessed quarterly at a portfolio-level for reasonableness versus comparable published rates. We reclassify gains and losses on the swaps out of AOCI and into earnings in those periods in which hedged interest payments occur. The following tables set forth the gains / (losses) recognized in AOCI and earnings related to the effective portion of derivative instruments and the gains / (losses) recognized in earnings related to the ineffective portion of derivative instruments in qualifying cash flow hedging relationships, as defined in the accounting standards for derivatives and hedging, for the periods indicated: Years ended December 31, 2016 2015 2014 $ in millions (net of tax) Power Interest Rate Hedges Power Interest Rate Hedges Power Interest Rate Hedges Beginning accumulated derivative gain in AOCI $ 9.2 $ 2.0 $ 0.2 $ 2.6 $ 1.0 $ 5.2 Net gains / (losses) associated with current period hedging transactions 15.7 0.4 18.2 — (18.8 ) — Net gains / (losses) reclassified to earnings: Interest Expense — (0.8 ) — (0.6 ) — (2.6 ) Revenues (35.6 ) — (12.0 ) — 18.2 — Purchased Power 6.4 — 2.8 — (0.2 ) — Ending accumulated derivative gain / (loss) in AOCI $ (4.3 ) $ 1.6 $ 9.2 $ 2.0 $ 0.2 $ 2.6 Net gains or losses associated with the ineffective portion of the hedging transactions were immaterial in the periods presented. Portion expected to be reclassified to earnings in the next twelve months (a) $ (3.5 ) $ (0.8 ) Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) 15 44 (a) The actual amounts that we reclassify from AOCI to earnings related to power can differ from the estimate above due to market price changes. Derivatives not designated as hedges Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for hedge accounting or the normal purchases and sales exceptions under FASC 815. Accordingly, such contracts are recorded at fair value with changes in the fair value charged or credited to the consolidated statements of operations in the period in which the change occurred. This is commonly referred to as “MTM accounting”. Contracts we enter into as part of our risk management program may be settled financially, by physical delivery or net settled with the counterparty. We mark to market FTRs, natural gas futures and certain forward power contracts. Certain qualifying derivative instruments have been designated as normal purchases or normal sales contracts, as provided under GAAP. Derivative contracts that have been designated as normal purchases or normal sales under GAAP are not subject to MTM accounting treatment and are recognized in the consolidated statements of operations on an accrual basis. Regulatory assets and liabilities In accordance with regulatory accounting under GAAP, a cost that is probable of recovery in future rates should be deferred as a regulatory asset and a gain that is probable of being returned to customers should be deferred as a regulatory liability. Portions of the derivative contracts that are marked to market each reporting period and are related to the retail portion of DP&L’s load requirements are included as part of the fuel and purchased power recovery rider approved by the PUCO which began January 1, 2010. Therefore, the Ohio retail customers’ portion of the heating oil futures are deferred as a regulatory asset or liability until the contracts settle. If these unrealized gains and losses are no longer deemed to be probable of recovery through our rates, they will be reclassified into earnings in the period such determination is made. The following tables show the amount and classification within the statements of operations or balance sheets of the gains and losses on DP&L’s derivatives not designated as hedging instruments for the years ended December 31, 2016 , 2015 and 2014 . Year ended December 31, 2016 $ in millions Heating Oil FTRs Power Natural Gas Total Derivatives not designated as hedging instruments Change in unrealized gain / (loss) $ — $ 0.3 $ 3.9 $ — $ 4.2 Realized gain / (loss) — (0.6 ) (7.9 ) 2.6 (5.9 ) Total $ — $ (0.3 ) $ (4.0 ) $ 2.6 $ (1.7 ) Recorded on Balance Sheet: Regulatory asset $ — $ — $ — $ — $ — Recorded in Statement of Operations: gain / (loss) Revenue — — (18.1 ) — (18.1 ) Purchased Power — (0.3 ) 14.1 2.6 16.4 Total $ — $ (0.3 ) $ (4.0 ) $ 2.6 $ (1.7 ) Year ended December 31, 2015 $ in millions Heating Oil FTRs Power Natural Gas Total Derivatives not designated as hedging instruments Change in unrealized gain / (loss) $ 0.4 $ 0.3 $ (6.3 ) $ 0.1 $ (5.5 ) Realized gain / (loss) (0.3 ) (0.2 ) (9.9 ) (0.1 ) (10.5 ) Total $ 0.1 $ 0.1 $ (16.2 ) $ — $ (16.0 ) Recorded on Balance Sheet: Regulatory asset $ 0.1 $ — $ — $ — $ 0.1 Recorded in Statement of Operations: gain / (loss) Revenue — — 27.4 — 27.4 Purchased Power — 0.1 (43.6 ) — (43.5 ) Total $ 0.1 $ 0.1 $ (16.2 ) $ — $ (16.0 ) Year ended December 31, 2014 $ in millions Heating Oil FTRs Power Natural Gas Total Derivatives not designated as hedging instruments Change in unrealized loss $ (0.6 ) $ (0.8 ) $ (1.5 ) $ (0.1 ) $ (3.0 ) Realized gain / (loss) (0.1 ) 0.7 (3.0 ) (0.1 ) (2.5 ) Total $ (0.7 ) $ (0.1 ) $ (4.5 ) $ (0.2 ) $ (5.5 ) Recorded on Balance Sheet: Regulatory (asset) / liability $ (0.1 ) $ — $ — $ — $ (0.1 ) Recorded in Statement of Operations: gain / (loss) Revenue — — 0.7 — 0.7 Fuel (0.6 ) — — — (0.6 ) Purchased Power — (0.1 ) (5.2 ) (0.2 ) (5.5 ) Total $ (0.7 ) $ (0.1 ) $ (4.5 ) $ (0.2 ) $ (5.5 ) The following tables show the fair value, balance sheet classification and hedging designation of DP&L’s derivative instruments at December 31, 2016 and 2015 . Fair Values of Derivative Instruments December 31, 2016 Gross Amounts Not Offset in the Balance Sheets $ in millions Hedging Designation Gross Fair Value as presented in the Balance Sheets Financial Instruments with Same Counterparty in Offsetting Position Cash Collateral Net Amount Assets Short-term derivative positions (presented in Other current assets) Forward power contracts Designated $ 11.0 $ (10.5 ) $ — $ 0.5 Forward power contracts Not designated 6.0 (4.7 ) — 1.3 FTRs Not designated 0.1 — — 0.1 Long-term derivative positions (presented in Other deferred assets) Forward power contracts Designated 0.6 (0.6 ) — — Interest Rate Swaps Designated 1.2 — — 1.2 Forward power contracts Not designated 1.9 (1.0 ) — 0.9 Total assets $ 20.8 $ (16.8 ) $ — $ 4.0 Liabilities Short-term derivative positions (presented in Other current liabilities) Forward power contracts Designated $ 16.4 $ (10.5 ) $ (5.5 ) $ 0.4 Interest Rate Swaps Designated 0.7 — — 0.7 Forward power contracts Not designated 7.7 (4.7 ) — 3.0 FTRs Not designated — — — — Long-term derivative positions (presented in Other deferred liabilities) Forward power contracts Designated 2.4 (0.6 ) (0.8 ) 1.0 Forward power contracts Not designated 2.0 (1.0 ) — 1.0 Total liabilities $ 29.2 $ (16.8 ) $ (6.3 ) $ 6.1 (a) Includes credit valuation adjustment. Fair Values of Derivative Instruments December 31, 2015 Gross Amounts Not Offset in the Balance Sheets $ in millions Hedging Designation Gross Fair Value as presented in the Balance Sheets Financial Instruments with Same Counterparty in Offsetting Position Cash Collateral Net Amount Assets Short-term derivative positions (presented in Other current assets) Forward power contracts Designated $ 16.2 $ (7.1 ) $ — $ 9.1 Forward power contracts Not designated 7.4 (5.5 ) — 1.9 FTRs Not designated 0.2 (0.2 ) — — Long-term derivative positions (presented in Other deferred assets) Forward power contracts Designated 3.0 (2.4 ) — 0.6 Forward power contracts Not designated 4.0 (2.7 ) — 1.3 Total assets $ 30.8 $ (17.9 ) $ — $ 12.9 Liabilities Short-term derivative positions (presented in Other current liabilities) Forward power contracts Designated $ 7.1 $ (7.1 ) $ — $ — Forward power contracts Not designated 14.5 (5.5 ) (8.0 ) 1.0 FTRs Not designated 0.5 (0.2 ) — 0.3 Long-term derivative positions (presented in Other deferred liabilities) Forward power contracts Designated 2.7 (2.4 ) — 0.3 Forward power contracts Not designated 2.7 (2.7 ) — — Total liabilities $ 27.5 $ (17.9 ) $ (8.0 ) $ 1.6 (a) Includes credit valuation adjustment. Credit risk-related contingent features Certain of our OTC commodity derivative contracts are under master netting agreements that contain provisions that require our debt to maintain an investment grade credit rating from credit rating agencies. Since our debt has fallen below investment grade, we are in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization of the MTM loss. Some of our counterparties to the derivative instruments have requested collateralization of the MTM loss. The aggregate fair value of DP&L’s derivative instruments that are in a MTM loss position at December 31, 2016 is $29.2 million . This amount is offset by $6.3 million of collateral posted directly with third parties and in a broker margin account which offsets our loss positions on the forward contracts. This liability position is further offset by the asset position of counterparties with master netting agreements of $16.8 million . If DP&L debt were to fall below investment grade, DP&L could be required to post collateral for the remaining $6.1 million . |
Goodwill and Other Intangible A
Goodwill and Other Intangible Assets | 12 Months Ended |
Dec. 31, 2016 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Goodwill and Intangible Assets | Goodwill Goodwill The following table summarizes the changes in Goodwill by reporting unit for the years ended December 31, 2015 and 2014: $ in millions DP&L Reporting Unit Balance at December 31, 2014 Goodwill $ 2,440.5 Accumulated impairment losses (2,123.5 ) Net balance at December 31, 2014 $ 317.0 Goodwill impairments during 2015 $ (317.0 ) Balance at December 31, 2015 Goodwill $ 2,440.5 Accumulated impairment losses (2,440.5 ) Net balance at December 31, 2015 $ — In connection with the acquisition of DPL by AES, DPL allocated the purchase price to goodwill for two reporting units, the DP&L reporting unit, which included DP&L and other entities, and DPLER. Of the total goodwill, approximately $2.4 billion was allocated to the DP&L reporting unit and the remainder was allocated to DPLER. Goodwill represented the value assigned at the Merger date, as adjusted for subsequent changes in the purchase price allocation, less recognized impairments. DPLER Reporting Unit During the first quarter of 2014, we performed an interim impairment test on the $135.8 million in goodwill at our DPLER reporting unit. During the second quarter of 2014, we finalized the work to determine the implied fair value for the DPLER reporting unit. There were no further adjustments to the full impairment of $135.8 million recognized in the first quarter. DPLER was sold on January 1, 2016 and is presented in discontinued operations on the Consolidated Statements of Operations. See Note 16 – Discontinued Operations for additional information. DP&L Reporting Unit During the fourth quarter of 2015, DPL performed its annual goodwill impairment test and recognized a goodwill impairment at its DP&L reporting unit of $317.0 million . The reporting unit failed Step 1 as its fair value was less than its carrying amount, which was primarily due to a decrease forecasted in dark spreads that were driven by decreases in projected forward power prices, and lower than expected revenues from the CP product. The fair value of the reporting unit was determined under the income approach using a discounted cash flow valuation model. The significant assumptions included within the discounted cash flow valuation model were forward commodity price curves, expected revenues from the new CP product, and planned environmental expenditures. In Step 2, goodwill was determined to have no implied fair value after the hypothetical purchase price allocation under the accounting guidance for business combinations; therefore, a full impairment of the remaining goodwill balance of $317.0 million was recognized. The goodwill associated with the Merger is not deductible for tax purposes. Accordingly, there is no cash or financial statement tax benefit related to the impairment. |
Debt
Debt | 12 Months Ended |
Dec. 31, 2016 | |
Debt Instrument [Line Items] | |
Debt | Debt Long-term debt $ in millions Interest Rate Maturity December 31, 2016 December 31, 2015 Term loan - rates from: 4.00% - 4.01% (a) 2022 $ 445.0 $ — First Mortgage Bonds 1.875% — 445.0 Tax-exempt First Mortgage Bonds 4.8% 2036 100.0 100.0 Tax-exempt First Mortgage Bonds - rates from: 1.29% - 1.42% (a) and 1.13% - 1.17% (b) 2020 200.0 200.0 U.S. Government note 4.2% 2061 18.0 18.1 Capital leases 0.4 — Unamortized deferred financing costs (10.7 ) (5.0 ) Unamortized debt discounts and premiums, net (5.5 ) (3.6 ) Total long-term debt at subsidiary 747.2 754.5 Bank term loan - rates from: 2.67% - 3.02% (a) and 2.44% - 2.67% (b) 2020 125.0 125.0 Senior unsecured bonds 6.5% — 130.0 Senior unsecured bonds 6.75% 2019 200.0 200.0 Senior unsecured bonds 7.25% 2021 780.0 780.0 Note to DPL Capital Trust II (c) 8.125% 2031 15.6 15.6 Unamortized deferred financing costs (8.8 ) (11.1 ) Unamortized debt discounts and premiums, net (0.6 ) (0.7 ) Subtotal 1,858.4 1,993.3 Less: current portion (29.7 ) (572.8 ) Total $ 1,828.7 $ 1,420.5 (a) Range of interest rates for the year ended December 31, 2016 . (b) Range of interest rates for the year ended December 31, 2015 . (c) Note payable to related party. See Note 13 – Related Party Transactions for additional information. At December 31, 2016 , maturities of long-term debt are summarized as follows: Due during the years ending December 31, $ in millions 2017 $ 29.7 2018 29.6 2019 229.6 2020 254.6 2021 784.6 Thereafter 555.5 1,883.6 Unamortized discounts and premiums, net (6.1 ) Total long-term debt $ 1,877.5 Premiums or discounts recognized at the Merger date are amortized over the life of the debt using the effective interest method. Significant transactions On July 1, 2015, the $35.3 million of DP&L's 4.7% tax-exempt First Mortgage Bonds due January 2028 and $41.3 million of DP&L's 4.8% tax-exempt First Mortgage Bonds due January of 2034 were called at par and were redeemed with cash. On July 31, 2015, DP&L refinanced its revolving credit facility. The new facility has a $175.0 million borrowing limit, with a $50.0 million letter of credit sublimit, a feature that provides DP&L the ability to increase the size of the facility by an additional $100.0 million and maturity date of July 2020. At December 31, 2016 , there were two letters of credit in the amount of $1.4 million outstanding, with the remaining $173.6 million available to DP&L . Fees associated with this revolving credit facility were not material during the years ended December 31, 2016 or 2015. Prior to refinancing the facility on July 31, 2015, this facility had a $300.0 million borrowing limit, a five -year term expiring on May 10, 2018, a $100.0 million letter of credit sublimit and a feature that provided DP&L the ability to increase the size of the facility by an additional $100.0 million . On August 3, 2015, DP&L called $100.0 million of variable rate tax-exempt First Mortgage Bonds due November 2040, terminated the amended standby letter of credit facilities that supported these tax-exempt First Mortgage Bonds, and called $137.8 million of 4.8% tax-exempt First Mortgage Bonds due January of 2034. DP&L also used cash to redeem $37.8 million of these bonds and refinanced the $200.0 million balance, with a new variable interest rate tax-exempt Term Loan secured by First Mortgage Bonds in an equivalent amount. In connection with the sale of the new tax-exempt First Mortgage Bonds, DP&L entered into a certain Bond Purchase and Covenants Agreement, dated as of August 1, 2015, containing representations, warranties, covenants and defaults consistent with those contained in the revolving credit facilities loan documents of DP&L . On November 21, 2016, the DP&L $200.0 million variable-rate Term Loan was hedged with floating for fixed rate interest rate swaps, reducing interest rate risk exposure for the term of the bonds. On July 31, 2015, DPL refinanced its revolving credit facility. The new facility has a total size of $205.0 million , a $200.0 million letter of credit sublimit, a feature that provides DPL the ability, under certain circumstances, to increase the size of the facility by an additional $95.0 million and a maturity date of July 2020. DPL's new credit facility also has a springing maturity feature providing that if, before July 1, 2019, DPL has not refinanced its senior unsecured bonds due October 2019 to have a maturity date that is at least six months later than July 31, 2020, then the maturity of this facility shall be July 1, 2019. This facility is secured by a pledge of common stock that DPL owns in DP&L , limited to the amount permitted to be pledged under certain Indentures dated October 3, 2011 and October 6, 2014 between DPL and Wells Fargo Bank, NA and U.S. Bank National Association, respectively, as Trustee and a limited recourse guarantee by AES Ohio Generation secured by mortgages on assets of AES Ohio Generation. At December 31, 2016 , there were two letters of credit in the amount of $1.7 million outstanding under this facility, with the remaining $203.3 million of the revolving credit facility remaining available to DPL . Fees associated with this facility were not material during the years ended December 31, 2016 or 2015 . Prior to refinancing the facility on July 31, 2015, this facility was unsecured and had a borrowing limit of $100.0 million with a $100.0 million letter of credit sublimit, was able to be increased in size by DPL by an additional $50.0 million and had a five -year term expiring on May 10, 2018; with a springing maturity, meaning that if DPL had not refinanced its senior unsecured bonds due October 2016 before July 15, 2016, then the maturity of this facility would have been July 15, 2016. Also on July 31, 2015, DPL refinanced its term loan, paying down the outstanding amount of $160.0 million using proceeds from the new term loan of $125.0 million and a combination of cash on hand and draws on short term credit facilities. The new term loan extends the term to July of 2020, pushing back required principal payments to 2017, and providing a mechanism for DPL to request additional term loans to refinance existing indebtedness. The new term loan has a springing maturity feature providing that if, before July 1, 2019, DPL has not refinanced its senior unsecured bonds due October 2019 to have a maturity date that is at least six months later than July 31, 2020, then the maturity of this facility shall be July 1, 2019 . This facility is secured by a pledge of common stock that DPL owns in DP&L , limited to the amount permitted to be pledged under certain Indentures dated October 3, 2011 and October 6, 2014 between DPL and Wells Fargo Bank, NA and U.S. Bank National Association, respectively, as Trustee and a limited recourse guarantee by AES Ohio Generation secured by mortgages on assets of AES Ohio Generation. The new term loan has a springing maturity feature providing that if, before July 1, 2019, DPL has not refinanced its senior unsecured bonds due October 2019 to have a maturity date that is at least six months later than July 31, 2020, then the maturity of this facility shall be July 1, 2019. In October 2014, DPL repaid $5.0 million of the note due to Capital Trust II, which used the funds to repurchase securities in the open market at a slight premium. Subsequent to repurchasing these securities, Capital Trust II immediately retired them. In October 2014, DPL closed a $200.0 million issuance of senior unsecured bonds. These new bonds were priced at 6.75% and mature on October 1, 2019. Proceeds from the issuance, in addition to a draw on the DPL revolving line of credit and cash on hand, were used to settle a tender offer for $300.0 million of the 6.50% senior unsecured notes maturing October 15, 2016. After this transaction, the DPL 6.5% Senior Notes due 2016 had an outstanding principal balance of $130.0 million . On January 6, 2016, DPL issued a Notice of Partial Redemption to the Trustee (Wells Fargo Bank N.A.) on the DPL 6.5% Senior Notes due 2016 (a component of the Dolphin Subsidiary II, Inc. debt). DPL notified the trustee that it was calling $73.0 million of the $130.0 million outstanding principal amount of these notes. The record date of this redemption was January 21, 2016, and the redemption date was February 5, 2016. These bonds were redeemed at par plus accrued interest and a make-whole premium of $2.4 million . On October 17, 2016, the remaining $57.0 million of outstanding principal was redeemed at par on their maturity date with cash on hand. On August 24, 2016, DP&L refinanced its 1.875% First Mortgage Bonds Due 2016, with a variable rate Term Loan B of $445.0 million maturing on August 24, 2022 and secured by a pledge of DP&L First Mortgage Bonds. The variable rate on the loan is calculated based on LIBOR plus a spread of 3.25% , with a LIBOR floor of 0.75% . Up to the maturity date but not starting until March 31, 2017, the loan amortizes 0.25% of the initial principal balance quarterly, and contains covenants and restrictions that are generally consistent with existing DP&L credit agreements. Debt covenants and restrictions DP&L’s unsecured revolving credit agreement and Bond Purchase and Covenants Agreement (financing document entered into in connection with the sale of the new $200.0 million of variable rate tax-exempt First Mortgage Bonds, dated as of August 1, 2015, containing representations, warranties, covenants and defaults consistent with those contained in the revolving credit facilities loan documents of DP&L ) have two financial covenants. The first measures Total Debt to Total Capitalization and is calculated, at the end of each fiscal quarter, by dividing total debt at the end of the quarter by total capitalization at the end of the quarter. The second financial covenant measures EBITDA to Interest Expense. The EBITDA to Interest Expense ratio is calculated, at the end of each fiscal quarter, by dividing consolidated EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period. DPL’s revolving credit agreement and term loan have two financial covenants. The first financial covenant, a Total Debt to EBITDA ratio, is calculated at the end of each fiscal quarter by dividing total debt at the end of the current quarter by consolidated EBITDA for the four prior fiscal quarters. The second financial covenant is an EBITDA to Interest Expense ratio that is calculated, at the end of each fiscal quarter, by dividing EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period. DP&L does not have any meaningful restrictions in its debt financing documents prohibiting dividends to its parent, DPL . DPL’s secured revolving credit agreement, secured term loan, and senior unsecured notes due 2019 restrict dividend payments from DPL to AES, such that DPL cannot make dividend payments unless at the time of, and/or as a result of, the distribution, DPL’s leverage ratio does not exceed 0.67 to 1.00 and DPL’s interest coverage ratio is not less than 2.50 to 1.00 or, if such ratios are not within the parameters, DPL’s senior long-term debt rating from one of the three major credit rating agencies is at least investment grade. As of December 31, 2016 , DPL’s leverage ratio was at 1.45 to 1.00 and DPL’s senior long-term debt rating from all three major credit rating agencies was below investment grade. As a result, as of December 31, 2016 , DPL was prohibited under each of these agreements from making a distribution to its shareholder or making a loan to any of its affiliates (other than its subsidiaries). DP&L’s revolving credit facility and Bond Purchase and Covenants Agreement (financing document entered into in connection with the issuance of the new $200.0 million of variable rate tax-exempt First Mortgage Bonds, dated as of August 1, 2015, containing representations, warranties and covenants consistent with those contained in DP&L's revolving credit facilities loan documents) have two financial covenants. First, prior to the date of completion of the separation of DP&L’s generation assets from its transmission and distribution assets, DP&L’s Total Debt to Total Capitalization may not be greater than 0.65 to 1.00 at any time; and, on and after the date of completion of the separation of DP&L’s generation assets from its transmission and distribution assets, DP&L’s Total Debt to Total Capitalization may not be greater than 0.75 to 1.00 at any time, except that after separation required compliance with this financial covenant shall be suspended (a) any time after separation during which DP&L maintains a rating of BBB- (or in the case of Moody’s Investors Service, Inc. Baa3) or higher with a stable outlook from at least one of Fitch Investors Service Inc., Standard & Poor’s Ratings Services or Moody’s Investors Service, Inc., as determined in accordance with the terms of the revolving credit facility or (b) for the time period January 1, 2017 to December 31, 2017 (as modified by the amendment described below) if during such time DP&L’s long-term indebtedness (as determined by the PUCO) is less than or equal to $750.0 million . The Total Debt to Capitalization covenant is calculated as the sum of DP&L’s current and long-term portion of debt, divided by the total of DP&L’s net worth and total debt. On February 21, 2017, DP&L and its lenders amended DP&L’s revolving credit agreement and Bond Purchase and Covenant Agreement. These amendments modified the definition of Consolidated Net Worth in each agreement (which is used for measuring the Total Debt to Total Capitalization ratio under each of the agreements), to exclude, through March 31, 2018, non-cash charges related directly to impairments of coal generation assets in DP&L's fiscal quarter ending December 31, 2016 and thereafter. With this amendment DP&L’s Total Debt to Total Capitalization ratio for the period ending December 31, 2016 is 0.53 to 1.00 , compared to 0.68 to 1.00 before the amendment. The amendment also changed, for each amendment, the dates after generation separation during which compliance with the Total Capitalization ratio detailed above shall be suspended if long-term indebtedness, as determined by the PUCO, is less than or equal to $750.0 million . As noted above this time period previously was January 1, 2017 to December 31, 2017, and is now the twelve months immediately subsequent to the separation of the generation assets from DP&L . As of December 31, 2016 , DP&L and DPL were in compliance with all debt covenants, including the financial covenants described above. |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Debt Instrument [Line Items] | |
Debt | Debt Long-term debt is as follows: Long-term debt $ in millions Interest Rate Maturity December 31, 2016 December 31, 2015 Term loan - rates from: 4.00% - 4.01% (a) 2022 $ 445.0 $ — First Mortgage Bonds 1.875% — 445.0 Tax-exempt First Mortgage Bonds 4.8% 2036 100.0 100.0 Tax-exempt First Mortgage Bonds - rates from: 1.29% - 1.42% (a) and 1.13% - 1.17% (b) 2020 200.0 200.0 U.S. Government note 4.2% 2061 18.0 18.1 Capital leases 0.4 — Unamortized deferred financing costs (11.8 ) (6.2 ) Unamortized debt discount (2.2 ) (0.2 ) Subtotal 749.4 756.7 Less: current portion (4.7 ) (443.1 ) Total $ 744.7 $ 313.6 (a) Range of interest rates for the year ended December 31, 2016 . (b) Range of interest rates for the year ended December 31, 2015 . At December 31, 2016 , maturities of long-term debt are summarized as follows: Due during the years ending December 31, $ in millions 2017 $ 4.7 2018 4.6 2019 4.6 2020 204.6 2021 4.5 Thereafter 540.0 763.0 Unamortized discounts and premiums, net (2.2 ) Total long-term debt $ 760.8 Significant transactions On December 31, 2016, DP&L borrowed $5.0 million from DPL at an interest rate of 3.02% . The notes were due on or before January 30, 2017 and were repaid on the maturity date. On August 24, 2016, DP&L refinanced its 1.875% First Mortgage Bonds due 2016, with a variable rate Term Loan B of $445.0 million maturing on August 24, 2022 and secured by a pledge of DP&L First Mortgage Bonds. The variable rate on the loan is calculated based on LIBOR plus a spread of 3.25% , with a LIBOR floor of 0.75% . Up to the maturity date but not starting until March 31, 2017, the loan amortizes 0.25% of the initial principal balance quarterly, and contains covenants and restrictions that are generally consistent with existing DP&L credit agreements. On December 31, 2015, DP&L borrowed $35.0 million from DPL at an interest rate of 2.67% . The notes were due on or before December 31, 2016 and were repaid on January 29, 2016. On July 1, 2015, the $35.3 million of DP&L's 4.7% tax-exempt First Mortgage Bonds due January 2028 and $41.3 million of DP&L's 4.8% tax-exempt First Mortgage Bonds due January of 2034 were called at par and were redeemed with cash. On July 31, 2015, DP&L refinanced its revolving credit facility. The new facility has a $175.0 million borrowing limit, a $50.0 million letter of credit sublimit, a feature that provides DP&L the ability to increase the size of the facility by an additional $100.0 million and a maturity date of July 2020. At December 31, 2016 , there were two letters of credit in the amount of $1.4 million outstanding, with the remaining $173.6 million available to DP&L . Fees associated with this revolving credit facility were not material during the years ended December 31, 2016 or 2015 . Prior to refinancing the facility on July 31, 2015, this facility had a $300.0 million borrowing limit, a five -year term expiring on May 10, 2018, a $100.0 million letter of credit sublimit and a feature that provided DP&L the ability to increase the size of the facility by an additional $100.0 million . On August 3, 2015, DP&L called $100.0 million of variable rate tax-exempt First Mortgage Bonds due November 2040, terminated the amended standby letter of credit facilities that supported these tax-exempt First Mortgage Bonds, and called $137.8 million of 4.8% tax-exempt First Mortgage Bonds due January of 2034. DP&L used cash to redeem $37.8 million of these bonds and refinanced the $200.0 million balance, with a new variable interest rate tax-exempt Term Loan secured by First Mortgage Bonds in an equivalent amount. In connection with the sale of the new tax-exempt First Mortgage Bonds, DP&L entered into a certain Bond Purchase and Covenants Agreement, dated as of August 1, 2015, containing representations, warranties, covenants and defaults consistent with those contained in the revolving credit facilities loan documents of DP&L . On November 21, 2016, the DP&L $200.0 million variable-rate Term Loan were hedged with floating for fixed rate interest rate swaps, reducing interest rate risk exposure for the term of the bonds. On March 31, 2014, DP&L borrowed $15.0 million from DPL at an interest rate of LIBOR plus 2.0% . This note was due on or before April 30, 2014 and was repaid on April 30, 2014. Debt covenants and restrictions In connection with DP&L’s sale of $200.0 million of variable rate tax-exempt First Mortgage Bonds dated August 1, 2015, DP&L entered into an unsecured revolving credit agreement and a Bond Purchase and Covenants Agreement. These agreements contain representations, warranties, covenants and defaults consistent with those contained in the revolving credit facilities loan documents of DP&L and have two financial covenants. The first measures Total Debt to Total Capitalization and is calculated, at the end of each fiscal quarter, by dividing total debt at the end of the quarter by total capitalization at the end of the quarter. The second financial covenant measures EBITDA to Interest Expense. The EBITDA to Interest Expense ratio is calculated, at the end of each fiscal quarter, by dividing EBITDA for the four prior fiscal quarters by the interest charges for the same period. DP&L’s revolving credit facility and Bond Purchase and Covenants Agreement (financing document entered into in connection with the issuance of the new $200.0 million of variable rate tax-exempt First Mortgage Bonds, dated as of August 1, 2015, containing representations, warranties and covenants consistent with those contained in DP&L's revolving credit facilities loan documents) have two financial covenants. First, prior to the date of completion of the separation of DP&L’s generation assets from its transmission and distribution assets, DP&L’s Total Debt to Total Capitalization may not be greater than 0.65 to 1.00 at any time; and, on and after the date of completion of the separation of DP&L’s generation assets from its transmission and distribution assets, DP&L’s Total Debt to Total Capitalization may not be greater than 0.75 to 1.00 at any time, except that after separation required compliance with this financial covenant shall be suspended (a) any time after separation during which DP&L maintains a rating of BBB- (or in the case of Moody’s Investors Service, Inc. Baa3) or higher with a stable outlook from at least one of Fitch Investors Service Inc., Standard & Poor’s Ratings Services or Moody’s Investors Service, Inc., as determined in accordance with the terms of the revolving credit facility or (b) for the time period January 1, 2017 to December 31, 2017 (as modified by the amendment described below) if during such time DP&L’s long-term indebtedness (as determined by the PUCO) is less than or equal to $750.0 million . The Total Debt to Capitalization covenant is calculated as the sum of DP&L’s current and long-term portion of debt, divided by the total of DP&L’s net worth and total debt. On February 21, 2017, DP&L and its lenders amended DP&L’s revolving credit agreement and Bond Purchase and Covenant Agreement. These amendments modified the definition of Consolidated Net Worth in each agreement (which is used for measuring the Total Debt to Total Capitalization ratio under each of the agreements), to exclude, through March 31, 2018, non-cash charges related directly to impairments of coal generation assets in DP&L's fiscal quarter ending December 31, 2016 and thereafter. With this amendment DP&L’s Total Debt to Total Capitalization ratio for the period ending December 31, 2016 is 0.53 to 1.00 , compared to 0.68 to 1.00 before the amendment. The amendment also changed, for each amendment, the dates after generation separation during which compliance with the Total Capitalization ratio detailed above shall be suspended if long-term indebtedness, as determined by the PUCO, is less than or equal to $750.0 million . As noted above this time period previously was January 1, 2017 to December 31, 2017, and is now the twelve months immediately subsequent to the separation of the generation assets from DP&L . As of December 31, 2016 , DP&L was in compliance with all debt covenants , including the financial covenants described above and did not have any meaningful restrictions in its debt financing documents prohibiting dividends to its parent, DPL . |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2016 | |
Income Taxes [Line Items] | |
Income Taxes | Income Taxes DPL’s components of income tax expense on continuing operations were as follows: Years ended December 31, $ in millions 2016 2015 2014 Computation of tax expense / (benefit) Federal income tax expense / (benefit) (a) $ (277.6 ) $ (81.0 ) $ 25.4 Increases (decreases) in tax resulting from: State income taxes, net of federal effect (1.0 ) (0.1 ) 0.8 Depreciation of AFUDC - Equity 2.7 (3.5 ) (3.4 ) Investment tax credit amortized (0.4 ) (0.5 ) (0.5 ) Section 199 - domestic production deduction (4.5 ) (4.1 ) (1.1 ) Non-deductible goodwill impairment — 111.0 — Accrual (settlement) for open tax years 2.2 — (6.6 ) Other, net (b) (0.2 ) (1.8 ) 0.8 Tax expense / (benefit) $ (278.8 ) $ 20.0 $ 15.4 Components of tax expense / (benefit) Federal - current $ 14.7 $ 30.1 $ (5.2 ) State and Local - current 0.6 0.8 0.4 Total current 15.3 30.9 (4.8 ) Federal - deferred (290.2 ) (9.9 ) 19.6 State and local - deferred (3.9 ) (1.0 ) 0.6 Total deferred (294.1 ) (10.9 ) 20.2 Tax expense / (benefit) $ (278.8 ) $ 20.0 $ 15.4 (a) The statutory tax rate of 35% was applied to pre-tax earnings. (b) Includes expense of $(0.3) million , $0.2 million and $0.4 million in the years ended December 31, 2016 , 2015 , and 2014 , respectively, of income tax related to adjustments from prior years. Effective and Statutory Rate Reconciliation The following table summarizes a reconciliation of the U.S. statutory federal income tax rate to DPL's effective tax rate, as a percentage of income from continuing operations before taxes for the years ended December 31, 2016 , 2015 and 2014 : Years ended December 31, 2016 2015 2014 Statutory Federal tax rate 35.0 % 35.0 % 35.0 % State taxes, net of Federal tax benefit 0.1 % 0.1 % 1.1 % AFUDC - Equity (0.3 )% 1.5 % (4.7 )% Amortization of investment tax credits — % 0.2 % (0.7 )% Section 199 - domestic production deduction 0.6 % 1.8 % (1.6 )% Non-deductible goodwill impairment — % (48.0 )% — % Other, net (0.3 )% 0.8 % (7.9 )% Effective tax rate 35.1 % (8.6 )% 21.2 % Deferred Income Taxes Deferred income taxes reflect the net tax effects of (a) temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes and (b) operating loss carryforwards. These items are stated at the enacted tax rates that are expected to be in effect when taxes are actually paid or recovered. Investment tax credits related to utility property have been deferred and are being amortized over the estimated useful lives of the related property. Components of Deferred Tax Assets and Liabilities December 31, $ in millions 2016 2015 Net non-current assets / (liabilities) Depreciation / property basis $ (255.3 ) $ (539.8 ) Income taxes recoverable (11.9 ) (12.0 ) Regulatory assets (7.8 ) (10.6 ) Investment tax credit 0.5 0.7 Compensation and employee benefits 5.5 3.1 Intangibles (1.5 ) (8.4 ) Long-term debt (0.7 ) (1.1 ) Other (a) 18.8 (0.6 ) Net non-current liabilities $ (252.4 ) $ (568.7 ) (a) The Other caption includes deferred tax assets of $24.9 million in 2016 and $26.0 million in 2015 related to state and local tax net operating loss carryforwards, net of related valuation allowances of $3.3 million in 2016 and $17.2 million in 2015 . These net operating loss carryforwards expire from 2017 to 2030. The following table presents the tax expense / (benefit) related to pensions, postemployment benefits, cash flow hedges and financial instruments that were credited to Accumulated other comprehensive loss. Years ended December 31, $ in millions 2016 2015 2014 Tax expense / (benefit) $ (9.6 ) $ 6.3 $ (9.1 ) Uncertain Tax Positions We apply the provisions of GAAP relating to the accounting for uncertainty in income taxes. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows: $ in millions Balance at December 31, 2014 $ 3.0 Calendar 2015 Tax positions taken during prior period — Lapse of Statute of Limitations — Balance at December 31, 2015 3.0 Calendar 2016 Tax positions taken during prior period 2.2 Lapse of Statute of Limitations (1.5 ) Balance at December 31, 2016 $ 3.7 Of the December 31, 2016 balance of unrecognized tax benefits, $0.9 million is due to uncertainty in the timing of deductibility. We recognize interest and penalties related to unrecognized tax benefits in Income tax expense. The amounts accrued as well as the expense / (benefit) recorded were not material for the years ended December 31, 2016 , 2015 and 2014 . Following is a summary of the tax years open to examination by major tax jurisdiction: U.S. Federal – 2011 and forward State and Local – 2011 and forward None of the unrecognized tax benefits are expected to significantly increase or decrease within the next twelve months other than those subject to expiring statute of limitations. |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Income Taxes [Line Items] | |
Income Taxes | Income Taxes DP&L’s components of income tax expense were as follows: Years ended December 31, $ in millions 2016 2015 2014 Computation of tax expense / (benefit) Federal income tax expense / (benefit) (a) $ (418.5 ) $ 49.3 $ 53.8 Increases (decreases) in tax resulting from: State income taxes, net of federal effect (5.0 ) 0.4 1.2 Depreciation of AFUDC - Equity 3.3 (2.8 ) (2.7 ) Investment tax credit amortized (2.3 ) (2.4 ) (2.5 ) Section 199 - domestic production deduction (5.3 ) (6.1 ) (4.6 ) Accrual (settlement) for open tax years 3.4 — (6.6 ) Other, net (b) 2.0 (3.3 ) 1.1 Tax expense / (benefit) $ (422.4 ) $ 35.1 $ 39.7 Components of tax expense / (benefit) Federal - current $ 51.6 $ 55.8 $ 34.1 State and Local - current 0.6 0.8 0.5 Total current 52.2 56.6 34.6 Federal - deferred (466.3 ) (21.0 ) 4.1 State and local - deferred (8.3 ) (0.5 ) 1.0 Total deferred (474.6 ) (21.5 ) 5.1 Tax expense / (benefit) $ (422.4 ) $ 35.1 $ 39.7 (a) The statutory tax rate of 35% was applied to pre-tax earnings. (b) Includes expense of $2.9 million , expense of $0.4 million and benefit of $0.7 million in the years ended December 31, 2016 , 2015 and 2014 , respectively, of income tax related to adjustments from prior years. Effective and Statutory Rate Reconciliation The following table summarizes a reconciliation of the U.S. statutory federal income tax rate to DP&L's effective tax rate, as a percentage of income from continuing operations before taxes for the years ended December 31, 2016 , 2015 and 2014 : Years ended December 31, 2016 2015 2014 Statutory Federal tax rate 35.0 % 35.0 % 35.0 % State taxes, net of Federal tax benefit 0.4 % 0.3 % 0.8 % AFUDC - Equity (0.3 )% (2.0 )% (1.7 )% Amortization of investment tax credits 0.2 % (1.7 )% (1.6 )% Section 199 - domestic production deduction 0.4 % (4.3 )% (3.0 )% Other - net (0.4 )% (2.5 )% (3.8 )% Effective tax rate 35.3 % 24.8 % 25.7 % Deferred Income Taxes Deferred income taxes reflect the net tax effects of (a) temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes and (b) operating loss carryforwards. These items are stated at the enacted tax rates that are expected to be in effect when taxes are actually paid or recovered. Investment tax credits related to utility property have been deferred and are being amortized over the estimated useful lives of the related property. Components of Deferred Tax Assets and Liabilities December 31, $ in millions 2016 2015 Net non-current Assets / (Liabilities) Depreciation / property basis $ (129.8 ) $ (608.8 ) Income taxes recoverable (11.9 ) (12.0 ) Regulatory assets (9.1 ) (11.5 ) Investment tax credit 6.3 7.0 Compensation and employee benefits 1.1 3.6 Other (2.9 ) (9.5 ) Net non-current liabilities $ (146.3 ) $ (631.2 ) The following table presents the tax (benefit) / expense related to pensions, postemployment benefits, cash flow hedges and financial instruments that were credited to Accumulated other comprehensive loss. Years ended December 31, $ in millions 2016 2015 2014 Tax expense / (benefit) $ (7.0 ) $ 7.5 $ (6.0 ) Uncertain Tax Positions We apply the provisions of GAAP relating to the accounting for uncertainty in income taxes. A reconciliation of the beginning and ending amount of unrecognized tax benefits for DP&L is as follows: $ in millions Balance at December 31, 2014 $ 3.0 Calendar 2015 Tax positions taken during prior period — Lapse of Statute of Limitations — Balance at December 31, 2015 3.0 Calendar 2016 Tax positions taken during prior period 3.4 Lapse of Statute of Limitations (1.5 ) Balance at December 31, 2016 $ 4.9 Of the December 31, 2016 balance of unrecognized tax benefits, $0.9 million is due to uncertainty in the timing of deductibility. We recognize interest and penalties related to unrecognized tax benefits in Income tax expense. The amounts accrued and expense (benefit) recorded were not material for each period presented. Following is a summary of the tax years open to examination by major tax jurisdiction: U.S. Federal – 2011 and forward State and Local – 2011 and forward None of the unrecognized tax benefits are expected to significantly increase or decrease within the next twelve months other than those subject to expiring statute of limitations. |
Benefit Plans
Benefit Plans | 12 Months Ended |
Dec. 31, 2016 | |
Benefit Plans | Benefit Plans Defined contribution plans DP&L sponsors two defined contribution plans. One is for non-union employees (the management plan) and one is for collective bargaining employees (the union plan). Both plans are qualified under Section 401 of the Internal Revenue Code. Certain non-union and union employees become eligible to participate in their respective plan upon date of hire. Participants may elect to contribute up to 85% of eligible compensation to their plan. Non-union participant contributions are matched 100% on the first 1% of eligible compensation and 50% on the next 5% of eligible compensation and they are fully vested in their employer contributions after 2 years of service. Union participant contributions are matched 150% but are capped at $2,200 for 2016 and they are fully vested in their employer contributions after 3 years of service. All participants are fully vested in their own contributions. For the years ended December 31, 2016 , 2015 and 2014 , DP&L's contributions to all defined contribution plans were $4.9 million , $4.8 million and $4.7 million per year, respectively. Defined benefit plans DP&L sponsors a traditional defined benefit pension plan for most of the employees of DPL and its subsidiaries. For collective bargaining employees, the defined benefits are based on a specific dollar amount per year of service. For all other employees (management employees), the traditional defined benefit pension plan is based primarily on compensation and years of service. As of December 31, 2010, this traditional pension plan was closed to new management employees. A participant is 100% vested in all amounts credited to his or her account upon the completion of five vesting years, as defined in The Dayton Power and Light Company Retirement Income Plan, or the participant’s death or disability. If a participant’s employment is terminated, other than by death or disability, prior to such participant becoming 100% vested in his or her account, the account shall be forfeited as of the date of termination. Effective January 1, 2014, the Service Company began providing services including accounting, legal, human resources, information technology and other corporate services on behalf of companies that are part of the U.S. SBU, including among other companies, DPL and DP&L . Employees that transferred from DP&L to the Service Company maintain their previous eligibility to participate in the DP&L pension plan. Almost all management employees beginning employment on or after January 1, 2011 participate in a cash balance pension plan. Similar to the traditional pension plan for management employees, the cash balance benefits are based on compensation and years of service. A participant shall become 100% vested in all amounts credited to his or her account upon the completion of three vesting years, as defined in The Dayton Power and Light Company Retirement Income Plan, or the participant’s death or disability. If a participant’s employment is terminated, other than by death or disability, prior to such participant becoming 100% vested in his or her account, the account shall be forfeited as of the date of termination. Vested benefits in the cash balance plan are fully portable upon termination of employment. In addition, we have a Supplemental Executive Retirement Plan (SERP) for certain retired key executives. The SERP has an immaterial unfunded liability related to agreements for retirement benefits of certain terminated and retired key executives. We also include our net liability to our partners in our co-owned generating plants related to our share of their pension costs within Pension, retiree and other benefits on our Consolidated Balance Sheets. We recognize an asset for a plan’s overfunded status and a liability for a plan’s underfunded status and recognize, as a component of OCI, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. For the transmission and distribution areas of our electric business, these amounts are recorded as regulatory assets and liabilities which represent the regulated portion that would otherwise be charged or credited to AOCI. We have historically recorded these costs on the accrual basis and this is how these costs have been historically recovered through customer rates. This factor, combined with the historical precedents from the PUCO and FERC, make these costs probable of future rate recovery. Postretirement benefits Qualified employees who retired prior to 1987 and their dependents are eligible for health care and life insurance benefits until their death, while qualified employees who retired after 1987 are eligible for life insurance benefits and partially subsidized health care. The partially subsidized health care is at the election of the employee, who pays the majority of the cost, and is available only from their retirement until they are covered by Medicare. We have funded a portion of the union-eligible benefits using a Voluntary Employee Beneficiary Association Trust. These postretirement health care benefits and the related unfunded obligation of $15.8 million and $15.0 million at December 31, 2016 and 2015 , respectively, were not material to the consolidated financial statements in the periods covered by this report. The following tables set forth the changes in our pension plan's obligations and assets recorded on the balance sheets at December 31, 2016 and 2015 . The amounts presented in the following tables for pension obligations include the collective bargaining plan formula, traditional management plan formula and cash balance plan formula and the SERP in the aggregate and have not been adjusted for $1.3 million and $2.2 million of costs billed to the service company for the years ended December 31, 2016 and 2015 . $ in millions Pension Years ended December 31, 2016 2015 Change in benefit obligation Benefit obligation at January 1 $ 410.8 $ 443.8 Service cost 5.7 7.1 Interest cost 14.7 17.3 Plan curtailment 2.5 — Actuarial (gain) / loss 9.0 (34.5 ) Benefits paid (23.1 ) (22.9 ) Benefit obligation at December 31 419.6 410.8 Change in plan assets Fair value of plan assets at January 1 345.4 371.7 Actual return on plan assets 13.3 (8.8 ) Employer contributions 5.4 5.4 Benefits paid (23.1 ) (22.9 ) Fair value of plan assets at December 31 341.0 345.4 Unfunded status of plan $ (78.6 ) $ (65.4 ) December 31, Amounts recognized in the Balance sheets 2016 2015 Current liabilities $ (0.4 ) $ (0.4 ) Non-current liabilities (78.2 ) (65.0 ) Net liability at December 31, $ (78.6 ) $ (65.4 ) Amounts recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax Components: Prior service cost $ 8.8 $ 12.0 Net actuarial loss 108.9 94.7 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 117.7 $ 106.7 Recorded as: Regulatory asset $ 97.1 $ 91.1 Accumulated other comprehensive income 20.6 15.6 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 117.7 $ 106.7 The accumulated benefit obligation for our defined benefit pension plans was $409.2 million and $401.2 million at December 31, 2016 and 2015 , respectively. The net periodic benefit cost of the pension plans were: Net Periodic Benefit Cost Years ended December 31, $ in millions 2016 2015 2014 Service cost $ 5.7 $ 7.1 $ 5.9 Interest cost 14.7 17.3 17.5 Expected return on assets (22.8 ) (22.6 ) (22.9 ) Plan curtailment 3.8 — — Amortization of unrecognized: Actuarial loss 4.3 5.8 3.4 Prior service cost 1.8 2.0 1.5 Net periodic benefit cost $ 7.5 $ 9.6 $ 5.4 Rates relevant to each year's expense calculations Discount rate 4.49 % 4.02 % 4.86 % Expected return on plan assets 6.50 % 6.50 % 6.75 % Other Changes in Plan Assets and Benefit Obligation Recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities Years ended December 31, $ in millions 2016 2015 2014 Net actuarial loss / (gain) $ 20.9 $ (3.0 ) $ 43.8 Prior service cost — — 6.8 Plan curtailment (3.8 ) — — Reversal of amortization item: Net actuarial loss (4.3 ) (5.8 ) (3.4 ) Prior service cost (1.8 ) (2.0 ) (1.5 ) Total recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities $ 11.0 $ (10.8 ) $ 45.7 Total recognized in net periodic benefit cost and Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities $ 18.5 $ (1.2 ) $ 51.1 Estimated amounts that will be amortized from AOCI, Regulatory assets and Regulatory liabilities into net periodic benefit costs during 2017 are: $ in millions Pension Actuarial loss $ 5.8 Prior service cost $ 1.4 Assumptions Our expected return on plan asset assumptions, used to determine benefit obligations, are based on historical long-term rates of return on investments, which use the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current market factors, such as inflation and interest rates, as well as asset diversification and portfolio rebalancing, are evaluated when long-term capital market assumptions are determined. Peer data and historical returns are reviewed to verify reasonableness and appropriateness. At December 31, 2016 , we are maintaining our long-term rate of return assumption of 6.50% for pension plan assets. The rate of return represents our long-term assumptions based on our long-term portfolio mix. Also, at December 31, 2016 , we have decreased our assumed discount rate to 4.28% from 4.49% for pension expense to reflect current duration-based yield curve discount rates. A one percent increase in the rate of return assumption for pension would result in a decrease in 2017 pension expense of approximately $3.5 million . A one percent decrease in the rate of return assumption for pension would result in an increase in 2017 pension expense of approximately $3.5 million . A 25 basis point increase in the discount rate for pension would result in a decrease of approximately $0.3 million to 2017 pension expense. A 25 basis point decrease in the discount rate for pension would result in an increase of approximately $0.4 million to 2017 pension expense. In determining the discount rate to use for valuing liabilities, we used a market yield curve on high-quality fixed income investments as of December 31, 2016 . We project the expected benefit payments under the plan based on participant data and based on certain assumptions concerning mortality, retirement rates, termination rates, etc. The expected benefit payments for each year are then discounted back to the measurement date using the appropriate spot rate for each half-year from the yield curve, thereby obtaining a present value of all expected future benefit payments using the yield curve. Finally, an equivalent single discount rate is determined which produces a present value equal to the present value determined using the full yield curve. Effective January 1, 2016, we applied a disaggregated discount rate approach for determining service cost and interest cost for our defined benefit pension plans and postretirement plans. See Note 1 – Overview and Summary of Significant Accounting Policies for more information. In future periods, differences in the actual return on pension plan assets and assumed return, or changes in the discount rate, will affect the timing of contributions, if any, to the plans. The weighted average assumptions used to determine benefit obligations at December 31, 2016 , 2015 and 2014 were: Benefit Obligation Assumptions Pension 2016 2015 2014 Discount rate for obligations 4.28% 4.49% 4.02% Rate of compensation increases 3.94% 3.94% 3.94% Pension plan assets Plan assets are invested using a total return investment approach whereby a mix of equity securities, debt securities and other investments are used to preserve asset values, diversify risk and achieve our target investment return benchmark. Investment strategies and asset allocations are based on careful consideration of plan liabilities, the plan's funded status and our financial condition. Investment performance and asset allocation are measured and monitored on an ongoing basis. Plan assets are managed in a balanced portfolio comprised of two major components: an equity portion and a fixed income portion. The expected role of plan equity investments is to maximize the long-term real growth of plan assets, while the role of fixed income investments is to generate current income, provide for more stable periodic returns and provide some protection against a prolonged decline in the market value of plan equity investments. Long-term strategic asset allocation guidelines, as well as short-term tactical asset allocation guidelines, are determined by a Risk/Advisory Committee and approved by a Fiduciary Committee. These allocations take into account the plan’s long-term objectives. The long-term target allocations for plan assets are 28% – 48% for equity securities and 42% – 70% for fixed income securities. Equity securities include U.S. and international equity, while fixed income securities include long-duration and high-yield bond funds and emerging market debt funds. Tactically, the committees, on a short-term basis, will make asset allocations that are outside the long-term allocation guidelines. The short-term allocation positions are likely to not exceed one-year in duration. In addition to the equity and fixed income investments, the short-term allocation may also include a relatively small allocation to alternative investments. The plan currently has a small target allocation of 6% to a core property fund. Most of our plan assets are measured using quoted, observable prices which are considered Level One inputs in the Fair Value Hierarchy. The Core property collective fund is measured using Level Two inputs that are quoted prices for identical assets in markets that are less active. The following table summarizes our target pension plan allocation for 2016 : Long-Term Target Allocation Percentage of plan assets as of December 31, Asset category 2016 2015 Equity Securities 38% 37% 17% Debt Securities 56% 53% 67% Real Estate 6% 10% 9% Other —% —% 7% The fair values of our pension plan assets at December 31, 2016 by asset category are as follows: Fair Value Measurements for Pension Plan Assets at December 31, 2016 Asset Category $ in millions Market Value at December 31, 2016 Quoted prices in active markets for identical assets Significant observable inputs Significant unobservable inputs (Level 1) (Level 2) (Level 3) Mutual funds: U.S. equities (a) $ 81.4 $ 81.4 $ — $ — International equities (a) 44.4 44.4 — — Fixed income (b) 151.1 151.1 — — Fixed income securities: U.S. Treasury securities 31.0 31.0 — — Other investments: Core property collective fund (c) 33.1 — 33.1 — Total pension plan assets $ 341.0 $ 307.9 $ 33.1 $ — (a) This category includes investments in equity securities of large, small and medium sized U.S. companies and equity securities of foreign companies including those in developing countries. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund. (b) This category includes investments in investment-grade fixed-income instruments, U.S. dollar-denominated debt securities of emerging market issuers and high yield fixed-income securities that are rated below investment grade. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund. (c) This category represents a property fund that invests in commercial real estate. The fair value of the fund is valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund. The fair values of our pension plan assets at December 31, 2015 by asset category are as follows: Fair Value Measurements for Pension Plan Assets at December 31, 2015 Asset Category $ in millions Market Value at December 31, 2015 Quoted prices in active markets for identical assets Significant observable inputs Significant unobservable inputs (Level 1) (Level 2) (Level 3) Mutual funds: U.S. equities (a) $ 39.4 $ 39.4 $ — $ — International equities (a) 20.9 20.9 — — Fixed income (b) 232.1 232.1 — — Other investments: (c) Core property collective fund 30.2 — 30.2 — Common collective fund 22.8 — 22.8 — Total pension plan assets $ 345.4 $ 292.4 $ 53.0 $ — (a) This category includes investments in equity securities of large, small and medium sized U.S. companies and equity securities of foreign companies including those in developing countries. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund. (b) This category includes investments in investment-grade fixed-income instruments, U.S. dollar-denominated debt securities of emerging market issuers and high yield fixed-income securities that are rated below investment grade. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund. (c) This category represents a property fund that invests in commercial real estate and a hedge fund of funds made up of 30+ different hedge fund managers diversified over eight different hedge strategies. The fair value of the hedge fund is valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund. Pension funding We generally fund pension plan benefits as accrued in accordance with the minimum funding requirements of the Employee Retirement Income Security Act of 1974 (ERISA) and, in addition, make voluntary contributions from time to time. We contributed $5.0 million , $5.0 million , and $0.0 million to the pension plan during the years ended December 31, 2016 , 2015 and 2014 , respectively. We expect to make contributions of $0.4 million to our SERP in 2017 to cover benefit payments. We made contributions of $5.0 million to our pension plan during January 2017 . Funding for the qualified Defined Benefit Pension Plan is based upon actuarially determined contributions that take into account the amount deductible for income tax purposes and the minimum contribution required under ERISA, as amended by the Pension Protection Act of 2006, as well as targeted funding levels necessary to meet certain thresholds. From an ERISA funding perspective, DP&L’s funded target liability percentage was estimated to be 100%. In addition, DP&L must also contribute the normal service cost earned by active participants during the plan year. The funding of normal cost is expected to be approximately $5.7 million in 2017 , which includes $0.6 million for plan expenses. Each year thereafter, if the plan’s underfunding increases to more than the present value of the remaining annual installments, the excess is separately amortized over a seven -year period. DP&L’s funding policy for the pension plans is to contribute annually no less than the minimum required by applicable law, and no more than the maximum amount that can be deducted for federal income tax purposes. Benefit payments, which reflect future service, are expected to be paid as follows: Estimated future benefit payments $ in millions due within the following years: Pension 2017 $ 25.0 2018 $ 25.5 2019 $ 26.0 2020 $ 26.4 2021 $ 26.7 2022 - 2026 $ 139.6 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Benefit Plans | Benefit Plans Defined contribution plans DP&L sponsors two defined contribution plans. One is for non-union employees (the management plan) and one is for collective bargaining employees (the union plan). Both plans are qualified under Section 401 of the Internal Revenue Code. Certain non-union and union employees become eligible to participate in their respective plan upon date of hire. Participants may elect to contribute up to 85% of eligible compensation to their plan. Non-union participant contributions are matched 100% on the first 1% of eligible compensation and 50% on the next 5% of eligible compensation and they are fully vested in their employer contributions after 2 years of service. Union participant contributions are matched 150% but are capped at $2,200 for 2016 and they are fully vested in their employer contributions after 3 years of service. All participants are fully vested in their own contributions. For the years ended December 31, 2016 , 2015 and 2014 DP&L's contributions to all defined contribution plans were $4.9 million , $4.8 million and $4.7 million per year, respectively. Defined benefit plans DP&L sponsors a traditional defined benefit pension plan for most of the employees of DPL and its subsidiaries. For collective bargaining employees, the defined benefits are based on a specific dollar amount per year of service. For all other employees (management employees), the traditional defined benefit pension plan is based primarily on compensation and years of service. As of December 31, 2010, this traditional pension plan was closed to new management employees. A participant is 100% vested in all amounts credited to his or her account upon the completion of five vesting years, as defined in The Dayton Power and Light Company Retirement Income Plan, or the participant’s death or disability. If a participant’s employment is terminated, other than by death or disability, prior to such participant becoming 100% vested in his or her account, the account shall be forfeited as of the date of termination. Effective January 1, 2014, the Service Company began providing services including accounting, legal, human resources, information technology and other corporate services on behalf of companies that are part of the U.S. SBU, including among other companies, DPL and DP&L . Employees that transferred from DP&L to the Service Company maintain their previous eligibility to participate in the DP&L pension plan. Almost all management employees beginning employment on or after January 1, 2011 participate in a cash balance pension plan. Similar to the traditional pension plan for management employees, the cash balance benefits are based on compensation and years of service. A participant shall become 100% vested in all amounts credited to his or her account upon the completion of three vesting years, as defined in The Dayton Power and Light Company Retirement Income Plan, or the participant’s death or disability. If a participant’s employment is terminated, other than by death or disability, prior to such participant becoming 100% vested in his or her account, the account shall be forfeited as of the date of termination. Vested benefits in the cash balance plan are fully portable upon termination of employment. In addition, we have a Supplemental Executive Retirement Plan (SERP) for certain retired key executives. The SERP has an immaterial unfunded liability related to agreements for retirement benefits of certain terminated and retired key executives. We also include our net liability to our partners in our co-owned generating plants related to our share of their pension costs within Pension, retiree and other benefits on our Balance Sheets. We recognize an asset for a plan’s overfunded status and a liability for a plan’s underfunded status and recognize, as a component of OCI, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. For the transmission and distribution areas of our electric business, these amounts are recorded as regulatory assets and liabilities which represent the regulated portion that would otherwise be charged or credited to AOCI. We have historically recorded these costs on the accrual basis and this is how these costs have been historically recovered through customer rates. This factor, combined with the historical precedents from the PUCO and FERC, make these costs probable of future rate recovery. Postretirement benefits Qualified employees who retired prior to 1987 and their dependents are eligible for health care and life insurance benefits until their death, while qualified employees who retired after 1987 are eligible for life insurance benefits and partially subsidized health care. The partially subsidized health care is at the election of the employee, who pays the majority of the cost, and is available only from their retirement until they are covered by Medicare. We have funded a portion of the union-eligible benefits using a Voluntary Employee Beneficiary Association Trust. These postretirement health care benefits and the related unfunded obligation of $15.8 million and $15.0 million at December 31, 2016 and 2015 , respectively, were not material to the financial statements in the periods covered by this report. The following tables set forth the changes in our pension plan's obligations and assets recorded on the balance sheets at December 31, 2016 and 2015 . The amounts presented in the following tables for pension obligations include the collective bargaining plan formula, traditional management plan formula and cash balance plan formula and the SERP in the aggregate and have not been adjusted for $1.3 million and $2.2 million of costs billed to the service company for the years ended December 31, 2016 and 2015 . $ in millions Pension Years ended December 31, 2016 2015 Change in benefit obligation Benefit obligation at January 1 $ 410.8 $ 443.8 Service cost 5.7 7.1 Interest cost 14.7 17.3 Plan curtailment 2.5 — Actuarial (gain) / loss 9.0 (34.5 ) Benefits paid (23.1 ) (22.9 ) Benefit obligation at December 31 419.6 410.8 Change in plan assets Fair value of plan assets at January 1 345.4 371.7 Actual return on plan assets 13.3 (8.8 ) Employer contributions 5.4 5.4 Benefits paid (23.1 ) (22.9 ) Fair value of plan assets at December 31 341.0 345.4 Funded status of plan $ (78.6 ) $ (65.4 ) December 31, Amounts recognized in the Balance sheets 2016 2015 Current liabilities $ (0.4 ) $ (0.4 ) Non-current liabilities (78.2 ) (65.0 ) Net liability $ (78.6 ) $ (65.4 ) Amounts recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax Components: Prior service cost $ 10.8 $ 17.0 Net actuarial loss 150.9 139.7 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 161.7 $ 156.7 Recorded as: Regulatory asset $ 97.1 $ 91.1 Accumulated other comprehensive income 64.6 65.6 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 161.7 $ 156.7 The accumulated benefit obligation for our defined benefit pension plans was $409.2 million and $401.2 million at December 31, 2016 and 2015 , respectively. The net periodic benefit cost of the pension plans were: Net Periodic Benefit Cost Years ended December 31, $ in millions 2016 2015 2014 Service cost $ 5.7 $ 7.1 $ 5.9 Interest cost 14.7 17.3 17.5 Expected return on assets (22.8 ) (22.6 ) (22.9 ) Plan curtailment 5.7 — — Amortization of unrecognized: Actuarial loss 7.2 9.8 6.4 Prior service cost 3.0 3.3 2.8 Net periodic benefit cost $ 13.5 $ 14.9 $ 9.7 Rates relevant to each year's expense calculations Discount rate 4.49 % 4.02 % 4.86 % Expected return on plan assets 6.50 % 6.50 % 6.75 % Other Changes in Plan Assets and Benefit Obligation Recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities Years ended December 31, $ in millions 2016 2015 2014 Net actuarial loss / (gain) $ 20.9 $ (3.0 ) $ 43.8 Prior service cost — — 6.8 Plan curtailment (5.7 ) — — Reversal of amortization item: Net actuarial loss (7.2 ) (9.8 ) (6.4 ) Prior service cost (3.0 ) (3.3 ) (2.8 ) Total recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities $ 5.0 $ (16.1 ) $ 41.4 Total recognized in net periodic benefit cost and Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities $ 18.5 $ (1.2 ) $ 51.1 Estimated amounts that will be amortized from AOCI, Regulatory assets and Regulatory liabilities into net periodic benefit costs during 2017 are: $ in millions Pension Actuarial loss $ 9.7 Prior service cost $ 1.9 Assumptions Our expected return on plan asset assumptions, used to determine benefit obligations, are based on historical long-term rates of return on investments, which use the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current market factors, such as inflation and interest rates, as well as asset diversification and portfolio rebalancing, are evaluated when long-term capital market assumptions are determined. Peer data and historical returns are reviewed to verify reasonableness and appropriateness. At December 31, 2016 , we are maintaining our long-term rate of return assumption of 6.50% for pension plan assets. The rate of return represents our long-term assumptions based on our long-term portfolio mix. Also, at December 31, 2016 , we have decreased our assumed discount rate to 4.28% from 4.49% for pension expense to reflect current duration-based yield curve discount rates. A one percent increase in the rate of return assumption for pension would result in a decrease in 2017 pension expense of approximately $3.5 million . A one percent decrease in the rate of return assumption for pension would result in an increase in 2017 pension expense of approximately $3.5 million . A 25 basis point increase in the discount rate for pension would result in a decrease of approximately $0.3 million to 2017 pension expense. A 25 basis point decrease in the discount rate for pension would result in an increase of approximately $0.4 million to 2017 pension expense. In determining the discount rate to use for valuing liabilities, we used a market yield curve on high-quality fixed income investments as of December 31, 2016 . We project the expected benefit payments under the plan based on participant data and based on certain assumptions concerning mortality, retirement rates, termination rates, etc. The expected benefit payments for each year are then discounted back to the measurement date using the appropriate spot rate for each half-year from the yield curve, thereby obtaining a present value of all expected future benefit payments using the yield curve. Finally, an equivalent single discount rate is determined which produces a present value equal to the present value determined using the full yield curve. Effective January 1, 2016, we applied a disaggregated discount rate approach for determining service cost and interest cost for our defined benefit pension plans and postretirement plans. See Note 1 – Overview and Summary of Significant Accounting Policies for more information. In future periods, differences in the actual return on pension plan assets and assumed return, or changes in the discount rate, will affect the timing of contributions, if any, to the plans. The weighted average assumptions used to determine benefit obligations at December 31, 2016 , 2015 and 2014 were: Benefit Obligation Assumptions Pension 2016 2015 2014 Discount rate for obligations 4.28% 4.49% 4.02% Rate of compensation increases 3.94% 3.94% 3.94% Pension plan assets Plan assets are invested using a total return investment approach whereby a mix of equity securities, debt securities and other investments are used to preserve asset values, diversify risk and achieve our target investment return benchmark. Investment strategies and asset allocations are based on careful consideration of plan liabilities, the plan's funded status and our financial condition. Investment performance and asset allocation are measured and monitored on an ongoing basis. Plan assets are managed in a balanced portfolio comprised of two major components: an equity portion and a fixed income portion. The expected role of plan equity investments is to maximize the long-term real growth of plan assets, while the role of fixed income investments is to generate current income, provide for more stable periodic returns and provide some protection against a prolonged decline in the market value of plan equity investments. Long-term strategic asset allocation guidelines, as well as short-term tactical asset allocation guidelines, are determined by a Risk/Advisory Committee and approved by a Fiduciary Committee. These allocations take into account the plan’s long-term objectives. The long-term target allocations for plan assets are 28% – 48% for equity securities and 42% – 70% for fixed income securities. Equity securities include U.S. and international equity, while fixed income securities include long-duration and high-yield bond funds and emerging market debt funds. Tactically, the committees, on a short-term basis, will make asset allocations that are outside the long-term allocation guidelines. The short-term allocation positions are likely to not exceed one-year in duration. In addition to the equity and fixed income investments, the short-term allocation may also include a relatively small allocation to alternative investments. The plan currently has a small target allocation of 6% to a core property fund. Most of our plan assets are measured using quoted, observable prices which are considered Level One inputs in the Fair Value Hierarchy. The Core property collective fund is measured using Level Two inputs that are quoted prices for identical assets in markets that are less active. The following table summarizes our target pension plan allocation for 2016 : Long-Term Target Allocation Percentage of plan assets as of December 31, Asset Category 2016 2015 Equity Securities 38% 37% 17% Debt Securities 56% 53% 67% Real Estate 6% 10% 9% Other —% —% 7% The fair values of our pension plan assets at December 31, 2016 by asset category are as follows: Fair Value Measurements for Pension Plan Assets at December 31, 2016 Asset Category $ in millions Market Value at December 31, 2016 Quoted prices in active markets for identical assets Significant observable inputs Significant unobservable inputs (Level 1) (Level 2) (Level 3) Mutual funds: U.S. equities (a) $ 81.4 $ 81.4 $ — $ — International equities (a) 44.4 44.4 — — Fixed income (b) 151.1 151.1 — — Fixed income securities U.S. Treasury securities 31.0 31.0 — — Other investments: Core property collective fund (c) 33.1 — 33.1 — Total pension plan assets $ 341.0 $ 307.9 $ 33.1 $ — (a) This category includes investments in equity securities of large, small and medium sized U.S. companies and equity securities of foreign companies including those in developing countries. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund. (b) This category includes investments in investment-grade fixed-income instruments, U.S. dollar-denominated debt securities of emerging market issuers and high yield fixed-income securities that are rated below investment grade. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund. (c) This category represents a property fund that invests in commercial real estate. The fair value of the fund is valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund. The fair values of our pension plan assets at December 31, 2015 by asset category are as follows: Fair Value Measurements for Pension Plan Assets at December 31, 2015 Asset Category $ in millions Market Value at December 31, 2015 Quoted prices in active markets for identical assets Significant observable inputs Significant unobservable inputs (Level 1) (Level 2) (Level 3) Mutual funds: U.S. equities (a) $ 39.4 $ 39.4 $ — $ — International equities (a) 20.9 20.9 — — Fixed income (b) 232.1 232.1 — — Other investments: (c) Core property collective fund 30.2 — 30.2 — Common collective fund 22.8 — 22.8 — Total pension plan assets $ 345.4 $ 292.4 $ 53.0 $ — (a) This category includes investments in equity securities of large, small and medium sized U.S. companies and equity securities of foreign companies including those in developing countries. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund. (b) This category includes investments in investment-grade fixed-income instruments, U.S. dollar-denominated debt securities of emerging market issuers and high yield fixed-income securities that are rated below investment grade. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund. (c) This category represents a property fund that invests in commercial real estate and a hedge fund of funds made up of 30+ different hedge fund managers diversified over eight different hedge strategies. The fair value of the hedge fund is valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund. Pension funding We generally fund pension plan benefits as accrued in accordance with the minimum funding requirements of the Employee Retirement Income Security Act of 1974 (ERISA) and, in addition, make voluntary contributions from time to time. We contributed $5.0 million , $5.0 million , and $0.0 million to the pension plan during the years ended December 31, 2016 , 2015 and 2014 , respectively. We expect to make contributions of $0.4 million to our SERP in 2017 to cover benefit payments. We made contributions of $5.0 million to our pension plan during January, 2017 . Funding for the qualified Defined Benefit Pension Plan is based upon actuarially determined contributions that take into account the amount deductible for income tax purposes and the minimum contribution required under ERISA, as amended by the Pension Protection Act of 2006, as well as targeted funding levels necessary to meet certain thresholds. From an ERISA funding perspective, DP&L’s funded target liability percentage was estimated to be 100%. In addition, DP&L must also contribute the normal service cost earned by active participants during the plan year. The funding of normal cost is expected to be approximately $5.7 million in 2017 , which includes $0.6 million for plan expenses. Each year thereafter, if the plan’s underfunding increases to more than the present value of the remaining annual installments, the excess is separately amortized over a seven -year period. DP&L’s funding policy for the pension plans is to contribute annually no less than the minimum required by applicable law, and no more than the maximum amount that can be deducted for federal income tax purposes. Benefit payments, which reflect future service, are expected to be paid as follows: Estimated future benefit payments $ in millions due within the following years: Pension 2017 $ 25.0 2018 $ 25.5 2019 $ 26.0 2020 $ 26.4 2021 $ 26.7 2022 - 2026 $ 139.6 |
Equity
Equity | 12 Months Ended |
Dec. 31, 2016 | |
Entity Information [Line Items] | |
Equity | Equity Redeemable Preferred Stock of Subsidiary DP&L had 228,508 shares of $100 par value preferred stock outstanding at December 31, 2015 and prior to the preferred stock redemption on October 13, 2016 (see below). The table below details the preferred shares outstanding at December 31, 2016 and 2015 : Carrying Value (b) ($ in millions) Preferred Stock Rate Redemption price ($ per share) Shares Outstanding (a) December 31, 2016 December 31, 2015 DP&L Series A 3.75% $ 102.50 93,280 $ — $ 7.4 DP&L Series B 3.75% $ 103.00 69,398 — 5.6 DP&L Series C 3.90% $ 101.00 65,830 — 5.4 Total 228,508 $ — $ 18.4 (a) DP&L's preferred stock was redeemed in October 2016. See below for more information. (b) Carrying value is fair value at the Merger date plus cumulative accrued dividends, of which there were none at December 31, 2016 and 2015 . DP&L’s Amended Articles of Incorporation contain provisions that permitted preferred stockholders to elect members of the Board of Directors in the event that cumulative dividends on the preferred stock are in arrears in an aggregate amount equivalent to at least four full quarterly dividends. Since this potential redemption-triggering event was not solely within the control of DP&L , the preferred stock was presented on the Consolidated Balance Sheets as “Redeemable Preferred Stock” in a manner consistent with temporary equity. On October 13, 2016 (the "Redemption Date"), DPL's subsidiary, DP&L redeemed all of its issued and outstanding preferred stock, consisting of the following series: Preferred Stock, 3.75% Series A, Cumulative (the “Series A Stock”); Preferred Stock, 3.75% Series B, Cumulative (the “Series B Stock”); and Preferred Stock, 3.90% Series C, Cumulative (the “Series C Stock” and, together with the Series A Stock and the Series B Stock, the “Preferred Stock”). On the Redemption Date, the Preferred Stock of each series was redeemed at the following prices as specified in DP&L’s Amended and Restated Articles of Incorporation, plus, in each case an amount equal to all accrued dividends payable with respect to such Preferred Stock to the Redemption Date: a price of $102.50 per share for the Series A Stock, a price of $103.00 per share for the Series B Stock, and a price of $101.00 per share for the Series C Stock. Dividends on the Preferred Stock ceased to accrue on the Redemption Date. Upon redemption, the Preferred Stock was no longer outstanding, and all rights of the holders thereof as shareholders of DP&L , except the right to payment of the redemption price, ceased to exist. The difference between the carrying value of the Redeemable Preferred Stock of Subsidiary and the redemption amount was charged to Other paid-in capital. Dividend Restrictions DPL’s Amended Articles of Incorporation (the Articles) contain provisions which state that DPL may not make a distribution to its shareholder or make a loan to any of its affiliates (other than its subsidiaries), unless: (a) there exists no Event of Default (as defined in the Articles) and no such Event of Default would result from the making of the distribution or loan; and either (b)(i) at the time of, and/or as a result of, the distribution or loan, DPL’s leverage ratio does not exceed 0.67 to 1.00 and DPL’s interest coverage ratio is not less than 2.50 to 1.00 or, (b)(ii) if such ratios are not within the parameters, DPL’s senior long-term debt rating from one of the three major credit rating agencies is at least investment grade. Further, the restrictions on the payment of distributions to a shareholder and the making of loans to its affiliates (other than subsidiaries) cease to be in effect if the three major credit rating agencies confirm that a lowering of DPL’s senior long-term debt rating below investment grade by the credit rating agencies would not occur without these restrictions. Common Stock Effective on the Merger date, DPL adopted Amended Articles of Incorporation provided for 1,500 authorized common shares, of which one share is outstanding at December 31, 2016 . As described above, DPL’s Amended Articles of Incorporation contain restrictions on DPL’s ability to make dividends, distributions and affiliate loans (other than to its subsidiaries), including restrictions of making such dividends, distributions and loans if certain financial ratios exceed specified levels and DPL’s senior long-term debt rating from a rating agency is below investment grade. As of December 31, 2016 , DPL’s leverage ratio was at 1.45 to 1.00 and DPL’s senior long-term debt rating from all three major credit rating agencies was below investment grade. As a result, as of December 31, 2016 , DPL was prohibited under its Articles of Incorporation from making a distribution to its shareholder or making a loan to any of its affiliates (other than its subsidiaries). DP&L has 250,000,000 authorized common shares, of which 41,172,173 are outstanding at December 31, 2016. All common shares are held by DP&L’s parent, DPL . As part of the PUCO’s approval of the Merger, DP&L agreed to maintain a capital structure that includes an equity ratio of at least 50 percent and not to have a negative retained earnings balance. After the fixed-asset impairments recorded during the second and fourth quarters of 2016 and as of December 31, 2016, DP&L's equity ratio was 32% and its retained earnings balance was negative. It is unknown what impact, if any, this will have on DP&L . |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Entity Information [Line Items] | |
Equity | Equity Redeemable Preferred Stock DP&L had 228,508 shares of $100 par value preferred stock outstanding at December 31, 2015 and prior to the preferred stock redemption on October 13, 2016 (see below). 4,000,000 shares authorized, of which 228,508 were outstanding at December 31, 2015. DP&L also has $25 par value preferred stock, 4,000,000 shares authorized, none of which was outstanding at December 31, 2016 . The table below details the preferred shares outstanding at December 31, 2016 and 2015 : Par Value ($ in millions) Preferred Stock Rate Redemption price ($ per share) Shares Outstanding (a) December 31, 2016 December 31, 2015 DP&L Series A 3.75% $ 102.50 93,280 $ — $ 9.3 DP&L Series B 3.75% $ 103.00 69,398 — 7.0 DP&L Series C 3.90% $ 101.00 65,830 — 6.6 Total 228,508 $ — $ 22.9 (a) DP&L's preferred stock was redeemed in October 2016. See below for more information. DP&L’s Amended Articles of Incorporation contain provisions that permitted preferred stockholders to elect members of the Board of Directors in the event that cumulative dividends on the preferred stock are in arrears in an aggregate amount equivalent to at least four full quarterly dividends. Since this potential redemption-triggering event was not solely within the control of DP&L , the preferred stock was presented on the Consolidated Balance Sheets as “Redeemable Preferred Stock” in a manner consistent with temporary equity. On October 13, 2016 (the "Redemption Date"), DP&L redeemed all of its issued and outstanding preferred stock, consisting of the following series: Preferred Stock, 3.75% Series A, Cumulative (the “Series A Stock”); Preferred Stock, 3.75% Series B, Cumulative (the “Series B Stock”); and Preferred Stock, 3.90% Series C, Cumulative (the “Series C Stock” and, together with the Series A Stock and the Series B Stock, the “Preferred Stock”). On the Redemption Date, the Preferred Stock of each series was redeemed at the following prices as specified in DP&L’s Amended and Restated Articles of Incorporation, plus, in each case an amount equal to all accrued dividends payable with respect to such Preferred Stock to the Redemption Date: a price of $102.50 per share for the Series A Stock, a price of $103.00 per share for the Series B Stock, and a price of $101.00 per share for the Series C Stock. Dividends on the Preferred Stock ceased to accrue on the Redemption Date. Upon redemption, the Preferred Stock was no longer outstanding, and all rights of the holders thereof as shareholders of DP&L , except the right to payment of the redemption price, ceased to exist. The difference between the carrying value of the Redeemable Preferred Stock of Subsidiary and the redemption amount was charged to Other paid-in capital. Common Stock DP&L has 250,000,000 authorized common shares, of which 41,172,173 are outstanding at December 31, 2016 . All common shares are held by DP&L’s parent, DPL . As part of the PUCO’s approval of the Merger, DP&L agreed to maintain a capital structure that includes an equity ratio of at least 50 percent and not to have a negative retained earnings balance. After the fixed-asset impairments recorded during the second and fourth quarters of 2016 and as of December 31, 2016, DP&L's equity ratio was 32% and its retained earnings balance was negative. It is unknown what impact, if any, this will have on DP&L . Equity settlement of related party payable DP&L settled a $7.5 million payable to DPL relating to income taxes. This payable balance was settled through equity and DPL's investment in DP&L was increased by $7.5 million as consideration for extinguishing the payable. |
Contractual Obligations, Commer
Contractual Obligations, Commercial Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2016 | |
Contractual Obligations, Commercial Commitments and Contingencies | Contractual Obligations, Commercial Commitments and Contingencies DPL – Guarantees In the normal course of business, DPL enters into various agreements with its wholly-owned subsidiary, AES Ohio Generation, providing financial or performance assurance to third parties. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to this subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish this subsidiary's intended commercial purposes. At December 31, 2016 , DPL had $16.6 million of guarantees on behalf of AES Ohio Generation to third parties for future financial or performance assurance under such agreements. The guarantee arrangements entered into by DPL with these third parties cover present and future obligations of AES Ohio Generation to such beneficiaries and are terminable at any time by DPL upon written notice to the beneficiaries. The carrying amount of obligations for commercial transactions covered by these guarantees and recorded in our Consolidated Balance Sheets was $2.3 million and $0.5 million at December 31, 2016 and 2015 , respectively. To date, DPL has not incurred any losses related to these guarantees and we believe it is remote that DPL would be required to perform or incur any losses in the future associated with any of the above guarantees. Equity Ownership Interest DP&L has a 4.9% equity ownership interest in OVEC which is recorded using the cost method of accounting under GAAP. At December 31, 2016 , DP&L could be responsible for the repayment of 4.9% , or $74.2 million , of a $1,514.3 million debt obligation comprised of both fixed and variable rate securities with maturities between 2017 and 2040 . This would only happen if this electric generation company defaulted on its debt payments. At December 31, 2016 , we have no knowledge of such a default. Contractual Obligations and Commercial Commitments We enter into various contractual obligations and other commercial commitments that may affect the liquidity of our operations. At December 31, 2016 , these include: Payments due in: $ in millions Total Less than 1 year 2 - 3 years 4 - 5 years More than 5 years DPL: Coal and limestone contracts (a) $ 284.3 $ 230.3 $ 54.0 $ — $ — Purchase orders and other contractual obligations $ 109.8 $ 43.1 $ 33.6 $ 33.1 $ — (a) Total at DP&L operated units. Coal contracts: DPL , through its principal subsidiary DP&L , has entered into various long-term coal contracts to supply the coal requirements for the generating stations it operates. At December 31, 2016 , 92% of our future committed coal obligations are with two suppliers. Some contract prices are subject to periodic adjustment and have features that limit price escalation in any given year. Purchase orders and other contractual obligations: At December 31, 2016 , DPL had various other contractual obligations, including non-cancelable contracts, to purchase goods and services with various terms and expiration dates. Contingencies In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in our Consolidated Financial Statements, as prescribed by GAAP, are adequate in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims, tax examinations, and other matters, including the matters discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our Consolidated Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided as of December 31, 2016 , cannot be reasonably determined. Environmental Matters DPL’s and DP&L’s facilities and operations are subject to a wide range of federal, state and local environmental regulations and laws. The environmental issues that may affect us include: • The federal CAA and state laws and regulations (including SIPs) which require compliance, obtaining permits and reporting as to air emissions, • Litigation with federal and certain state governments and certain special interest groups regarding whether modifications to or maintenance of certain coal-fired generating stations require additional permitting or pollution control technology, or whether emissions from coal-fired generating stations cause or contribute to global climate changes, • Rules and future rules issued by the USEPA and the Ohio EPA that require substantial reductions in SO 2 , particulates, mercury, acid gases, NO X , and other air emissions. DP&L has installed emission control technology and is taking other measures to comply with required and anticipated reductions, • Rules and future rules issued by the USEPA and the Ohio EPA that require reporting and reductions of GHGs, • Rules and future rules issued by the USEPA associated with the federal Clean Water Act, which prohibits the discharge of pollutants into waters of the United States except pursuant to appropriate permits, and • Solid and hazardous waste laws and regulations, which govern the management and disposal of certain waste. The majority of solid waste created from the combustion of coal and fossil fuels is fly ash and other coal combustion by-products. In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. In the normal course of business, we have investigatory and remedial activities underway at our facilities to comply, or to determine compliance, with such regulations. We record liabilities for loss contingencies related to environmental matters when a loss is probable of occurring and can be reasonably estimated in accordance with the provisions of GAAP. Accordingly, we have immaterial accruals for loss contingencies for environmental matters. We also have a number of environmental matters for which we have not accrued loss contingencies because the risk of loss is not probable or a loss cannot be reasonably estimated. We evaluate the potential liability related to environmental matters quarterly and may revise our estimates. Such revisions in the estimates of the potential liabilities could have a material adverse effect on our results of operations, financial condition or cash flows. We have several pending environmental matters associated with our coal-fired generation units. Some of these matters could have material adverse impacts on the operation of the power stations. |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Contractual Obligations, Commercial Commitments and Contingencies | Contractual Obligations, Commercial Commitments and Contingencies DP&L – Equity Ownership Interest DP&L has a 4.9% equity ownership interest in an electric generation company which is recorded using the cost method of accounting under GAAP. At December 31, 2016 , DP&L could be responsible for the repayment of 4.9% , or $74.2 million , of a $1,514.3 million debt obligation comprised of both fixed and variable rate securities with maturities between 2017 and 2040 . This would only happen if this electric generation company defaulted on its debt payments. At December 31, 2016 , we have no knowledge of such a default. Contractual Obligations and Commercial Commitments We enter into various contractual obligations and other commercial commitments that may affect the liquidity of our operations. At December 31, 2016 , these include: Payments due in: $ in millions Total Less than 1 year 2 - 3 years 4 - 5 years More than 5 years DP&L: Coal and limestone contracts (a) $ 284.3 $ 230.3 $ 54.0 $ — $ — Purchase orders and other contractual obligations $ 109.8 $ 43.1 $ 33.6 $ 33.1 $ — (a) Total at DP&L operated units. Coal contracts: DP&L has entered into various long-term coal contracts to supply the coal requirements for the generating stations it operates. At December 31, 2016 , 92% of our future committed coal obligations are with two suppliers. Some contract prices are subject to periodic adjustment and have features that limit price escalation in any given year. Purchase orders and other contractual obligations: At December 31, 2016 , DP&L had various other contractual obligations, including non-cancelable contracts, to purchase goods and services with various terms and expiration dates. Contingencies In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in our Financial Statements, as prescribed by GAAP, are adequate in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims, tax examinations, and other matters, including the matters discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided as of December 31, 2016 , cannot be reasonably determined. Environmental Matters DP&L’s facilities and operations are subject to a wide range of federal, state and local environmental regulations and laws. The environmental issues that may affect us include: • The federal CAA and state laws and regulations (including SIPs) which require compliance, obtaining permits and reporting as to air emissions, • Litigation with federal and certain state governments and certain special interest groups regarding whether modifications to or maintenance of certain coal-fired generating stations require additional permitting or pollution control technology, or whether emissions from coal-fired generating stations cause or contribute to global climate changes, • Rules and future rules issued by the USEPA and the Ohio EPA that require substantial reductions in SO 2 , particulates, mercury, acid gases, NO X , and other air emissions. DP&L has installed emission control technology and is taking other measures to comply with required and anticipated reductions, • Rules and future rules issued by the USEPA and the Ohio EPA that require reporting and reductions of GHGs, • Rules and future rules issued by the USEPA associated with the federal Clean Water Act, which prohibits the discharge of pollutants into waters of the United States except pursuant to appropriate permits, and • Solid and hazardous waste laws and regulations, which govern the management and disposal of certain waste. The majority of solid waste created from the combustion of coal and fossil fuels is fly ash and other coal combustion by-products. In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. In the normal course of business, we have investigatory and remedial activities underway at our facilities to comply, or to determine compliance, with such regulations. We record liabilities for loss contingencies related to environmental matters when a loss is probable of occurring and can be reasonably estimated in accordance with the provisions of GAAP. Accordingly, we have immaterial accruals for loss contingencies for environmental matters. We also have a number of environmental matters for which we have not accrued loss contingencies because the risk of loss is not probable or a loss cannot be reasonably estimated. We evaluate the potential liability related to environmental matters quarterly and may revise our estimates. Such revisions in the estimates of the potential liabilities could have a material adverse effect on our results of operations, financial condition or cash flows. We have several pending environmental matters associated with our coal-fired generation units. Some of these matters could have material adverse impacts on the operation of the power stations. |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2016 | |
Entity Information [Line Items] | |
Related Party Transactions | Related Party Transactions Service Company Effective January 1, 2014, the Service Company began providing services including operations, accounting, legal, human resources, information technology and other corporate services on behalf of companies that are part of the U.S. SBU, including, among other companies, DPL and DP&L . The Service Company allocates the costs for these services based on cost drivers designed to result in fair and equitable allocations. This includes ensuring that the regulated utilities served, including DP&L , are not subsidizing costs incurred for the benefit of other businesses. Benefit plans DPL participates in an agreement with Health and Welfare Benefit Plans LLC, an affiliate of AES, to participate in a group benefits program, including but not limited to, health, dental, vision and life benefits. Health and Welfare Benefit Plans LLC administers the financial aspects of the group insurance program, receives all premium payments from the participating affiliates, and makes all vendor payments. Long-term Compensation Plan During 2016 , 2015 and 2014 , many of DPL’s non-union employees received benefits under the AES Long-term Compensation Plan, a deferred compensation program. This type of plan is a common employee retention tool used in our industry. Benefits under this plan are granted in the form of performance units payable in cash and AES restricted stock units and options to purchase shares of AES common stock, however no stock options were granted in 2016. All such components vest over a three-year period and the terms of the AES restricted stock unit issued prior to 2011 also include a two year minimum holding period after the awards vest. Awards made in 2011 and for subsequent years are not subject to a two year holding period. In addition, the performance units payable in cash are subject to certain AES performance criteria. Total deferred compensation expense recorded during 2016 , 2015 and 2014 was $0.5 million , $0.5 million and $0.0 million , respectively, and was included in “ Other Operating Expenses” on DPL’s Consolidated Statements of Operations. The value of these benefits is being recognized over the 36 month vesting period and a portion is recorded as miscellaneous deferred credits with the remainder recorded as “ Paid in capital” on DPL’s Consolidated Balance Sheets in accordance with FASC 718 “Compensation - Stock Compensation.” The following table provides a summary of these transactions: For the years ended December 31, $ in millions 2016 2015 2014 Transactions with the Service Company Charges for services provided $ 42.8 $ 36.0 $ 35.8 Charges to the Service Company $ 4.6 $ 6.2 $ 2.4 Transactions with other AES affiliates: Payments for health, welfare and benefit plans $ 9.6 $ 15.5 $ 17.8 Balances with related parties: At December 31, 2016 At December 31, 2015 Net payable to the Service Company $ (2.0 ) $ (0.5 ) Net prepayment with / (payable) to other AES affiliates $ (2.5 ) $ 0.1 DPL Capital Trust II DPL has a wholly-owned business trust, DPL Capital Trust II (the Trust), formed for the purpose of issuing trust capital securities to third-party investors. Effective in 2003, DPL deconsolidated the Trust upon adoption of the accounting standards related to variable interest entities and currently treats the Trust as a nonconsolidated subsidiary. The Trust holds mandatorily redeemable trust capital securities. The investment in the Trust, which amounts to $0.3 million and $0.3 million at December 31, 2016 and 2015 , respectively, is included in Other deferred assets within Other noncurrent assets. DPL also has a note payable to the Trust amounting to $15.6 million and $15.6 million at December 31, 2016 and 2015 , respectively, that was established upon the Trust’s deconsolidation in 2003. See Note 8 – Debt for additional information. In addition to the obligations under the note payable mentioned above, DPL also agreed to a security obligation which represents a full and unconditional guarantee of payments to the capital security holders of the Trust. Income taxes AES files federal and state income tax returns which consolidate DPL and its subsidiaries. Under a tax sharing agreement with AES, DPL is responsible for the income taxes associated with its own taxable income and records the provision for income taxes using a separate return method. Under this agreement, DPL had a net receivable balance of $97.2 million and $50.5 million at December 31, 2016 and 2015, respectively, which is recorded in Other current assets on the accompanying Balance Sheets. |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Entity Information [Line Items] | |
Related Party Transactions | Related Party Transactions Service Company Effective January 1, 2014, the Service Company began providing services including operations, accounting, legal, human resources, information technology and other corporate services on behalf of companies that are part of the U.S. SBU, including, among other companies, DPL and DP&L . The Service Company allocates the costs for these services based on cost drivers designed to result in fair and equitable allocations. This includes ensuring that the regulated utilities served, including DP&L , are not subsidizing costs incurred for the benefit of other businesses. Benefit plans DPL participates in an agreement with Health and Welfare Benefit Plans LLC, an affiliate of AES, to participate in a group benefits program, including but not limited to, health, dental, vision and life benefits. Health and Welfare Benefit Plans LLC administers the financial aspects of the group insurance program, receives all premium payments from the participating affiliates, and makes all vendor payments. Long-term Compensation Plan During 2016 , 2015 and 2014 , many of DP&L’s non-union employees received benefits under the AES Long-term Compensation Plan, a deferred compensation program. This type of plan is a common employee retention tool used in our industry. Benefits under this plan are granted in the form of performance units payable in cash and AES restricted stock units and options to purchase shares of AES common stock, however no stock options were granted in 2016. All such components vest over a three-year period and the terms of the AES restricted stock unit issued prior to 2011 also include a two year minimum holding period after the awards vest. Awards made in 2011 and for subsequent years are not subject to a two year holding period. In addition, the performance units payable in cash are subject to certain AES performance criteria. Total deferred compensation expense recorded during 2016 , 2015 and 2014 was $0.5 million , $0.5 million and $0.0 million , respectively, and was included in “ Other Operating Expenses” on DP&L’s Statements of Operations. The value of these benefits is being recognized over the 36 month vesting period and a portion is recorded as miscellaneous deferred credits with the remainder recorded as “ Paid in capital” on DP&L’s Balance Sheets in accordance with FASC 718 “Compensation - Stock Compensation.” The following table provides a summary of these transactions: Years ended December 31, $ in millions 2016 2015 2014 DP&L revenues: Sales to DPLER (including MC Squared) (a) $ — $ 303.3 $ 487.1 DP&L Operation & Maintenance Expenses: Premiums paid for insurance services provided by MVIC (b) $ (3.4 ) $ (3.2 ) $ (2.9 ) Expense recoveries for services provided to DPLER (c) $ — $ 2.4 $ 2.2 Transactions with the Service Company: Charges for services provided $ 38.7 $ 30.9 $ 30.5 Charges to the Service Company $ 4.5 $ 6.1 $ 2.3 Transactions with other AES affiliates: Payments for health, welfare and benefit plans $ 9.4 $ 14.8 $ 17.1 Balances with related parties: At December 31, 2016 At December 31, 2015 Net payable to the Service Company $ (2.0 ) $ (0.5 ) Short-term loan with DPL $ 5.0 $ 35.0 Net prepayment with / (payable) to other AES affiliates $ (2.5 ) $ 0.1 (a) DP&L sold power to DPLER and MC Squared to satisfy the electric requirements of their retail customers. The revenue dollars associated with sales to DPLER and MC Squared are recorded as wholesale revenues in DP&L’s Financial Statements. These agreements were terminated on the sale of DPLER on January 1, 2016. (b) MVIC, a wholly-owned captive insurance subsidiary of DPL , provides insurance coverage to DP&L and other DPL subsidiaries for workers’ compensation, general liability, property damages and directors’ and officers’ liability. These amounts represent insurance premiums paid by DP&L to MVIC. (c) In the normal course of business DP&L incurred and recorded expenses on behalf of DPLER. Such expenses included but were not limited to employee-related expenses, accounting, information technology, payroll, legal and other administration expenses. DP&L subsequently charged these expenses to DPLER at DP&L’s cost and credited the expense in which they were initially recorded. Income taxes AES files federal and state income tax returns which consolidate DPL and its subsidiaries, including DP&L . Under a tax sharing agreement with DPL , DP&L is responsible for the income taxes associated with its own taxable income and records the provision for income taxes using a separate return method. Under this agreement, DP&L had a net receivable balance of $9.5 million and $1.5 million at December 31, 2016 and 2015, respectively, which is recorded in Other current assets on the accompanying Balance Sheets. |
Business Segments
Business Segments | 12 Months Ended |
Dec. 31, 2016 | |
Segment Reporting Information [Line Items] | |
Business Segments | Business Segments During the fourth quarter of 2016, DPL's management reassessed our reportable business segments in connection with recent changes in the regulatory environment, including the pending ESP case, and in preparation for the anticipated transfer of DP&L’s generation assets to AES Ohio Generation. DPL currently manages the business through two reportable operating segments, the Transmission and Distribution ("T&D") segment and the Generation segment. The primary segment performance measure is income / (loss) from continuing operations before income tax as management has concluded that income / (loss) from continuing operations before income tax best reflects the underlying business performance of DPL and is the most relevant measure considered in DPL’s internal evaluation of the financial performance of its segments. The segments are discussed further below: Transmission and Distribution Segment The T&D segment is comprised primarily of DP&L’s electric transmission and distribution businesses, which distribute electricity to residential, commercial, industrial and governmental customers. DP&L distributes electricity to more than 519,000 retail customers who are located in a 6,000 square mile area of West Central Ohio. DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates, and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs. The T&D segment includes revenues and costs associated with our investment in OVEC and the historical results of DP&L’s Beckjord, Hutchings Coal, and East Bend generating facilities, which were either closed or sold in prior periods. As these assets will not be transferring to AES Ohio Generation when DP&L’s planned generation separation occurs, they are grouped with the T&D assets for segment reporting purposes. In addition, regulatory deferrals and collections, which include fuel deferrals in historical periods, are included in the T&D segment. Generation Segment The Generation segment is comprised of AES Ohio Generation and DP&L’s electric generation business. Beginning in 2001, Ohio law gave consumers the right to choose the electric generation supplier from whom they purchase retail generation services. AES Ohio Generation owns and operates peaking generating facilities, and DP&L owns multiple coal-fired and peaking electric generating facilities. Both AES Ohio Generation and DP&L primarily sell their generated energy and capacity into the PJM wholesale market as DP&L sources all of the generation for its SSO customers through a competitive bid process. Prior to the January 1, 2016 sale of DPLER, DP&L also had full requirements sales to DPLER. Included within the “Other” column are other businesses that do not meet the GAAP requirements for disclosure as reportable segments as well as certain corporate costs, which include interest expense on DPL’s debt and adjustments related to purchase accounting from the Merger. The accounting policies of the reportable segments are the same as those described in Note 1 – Overview and Summary of Significant Accounting Policies . Intersegment sales and profits are eliminated in consolidation. Certain shared and corporate costs are allocated among reporting segments. The following tables present financial information for each of DPL’s reportable business segments: $ in millions T&D Generation Other Adjustments and Eliminations DPL Consolidated Year ended December 31, 2016 Revenues from external customers $ 806.7 $ 611.5 $ 9.1 $ — $ 1,427.3 Intersegment revenues 1.3 — 5.7 (7.0 ) — Total revenues $ 808.0 $ 611.5 $ 14.8 $ (7.0 ) $ 1,427.3 Depreciation and amortization $ 71.0 $ 55.4 $ 5.9 $ — $ 132.3 Fixed-asset impairment (Note 15) $ — $ 1,353.5 $ (494.5 ) $ — $ 859.0 Interest expense $ 24.7 $ 0.4 $ 81.3 $ (0.3 ) $ 106.1 Income / (loss) from continuing operations before income tax $ 143.0 $ (1,353.9 ) $ 417.6 $ — $ (793.3 ) Cash capital expenditures $ 83.4 $ 64.2 $ 0.9 $ — $ 148.5 Total assets (end of year) $ 1,710.5 $ 472.3 $ 673.6 $ (437.2 ) $ 2,419.2 $ in millions T&D Generation Other Adjustments and Eliminations DPL Consolidated Year ended December 31, 2015 Revenues from external customers (b) $ 855.5 $ 770.3 $ 6.7 $ (19.7 ) $ 1,612.8 Intersegment revenues 1.5 186.6 4.2 (192.3 ) — Total revenues $ 857.0 $ 956.9 $ 10.9 $ (212.0 ) $ 1,612.8 Depreciation and amortization $ 71.5 $ 72.6 $ (9.5 ) $ — $ 134.6 Goodwill impairment (Note 7) $ — $ — $ 317.0 $ — $ 317.0 Interest expense $ 28.9 $ 2.9 $ 86.8 $ (0.3 ) $ 118.3 Income / (loss) from continuing operations before income tax $ 188.1 $ (28.7 ) $ (390.8 ) $ — $ (231.4 ) Cash capital expenditures $ 98.3 $ 35.2 $ 3.7 $ — $ 137.2 Total assets (end of year) (a) $ 1,688.8 $ 1,805.0 $ 1,170.3 $ (1,339.4 ) $ 3,324.7 (a) Includes assets held for sale related to the sale of DPLER. (b) Wholesale revenue for the T&D segment in 2015 includes OVEC revenue of $19.7 million that was previously netted in purchased power. The impact of this netting adjustment is included in the Adjustments and Eliminations column in the table above but has no impact on consolidated revenues or Income / (loss) from continuing operations before income tax. $ in millions T&D Generation Other Adjustments and Eliminations DPL Consolidated Year ended December 31, 2014 Revenues from external customers (b) $ 1,020.1 $ 721.8 $ 7.1 $ (32.5 ) $ 1,716.5 Intersegment revenues 1.7 72.8 3.8 (78.3 ) — Total revenues $ 1,021.8 $ 794.6 $ 10.9 $ (110.8 ) $ 1,716.5 Depreciation and amortization $ 75.5 $ 75.3 $ (15.2 ) $ — $ 135.6 Fixed asset impairment (Note 15) $ — $ — $ 11.5 $ — $ 11.5 Interest expense $ 29.8 $ 5.0 $ 92.5 $ (0.7 ) $ 126.6 Income / (loss) from continuing operations before income tax $ 241.7 $ (78.0 ) $ (91.1 ) $ — $ 72.6 Cash capital expenditures $ 100.4 $ 14.5 $ 3.2 $ — $ 118.1 Total assets (end of year) (a) $ 1,686.1 $ 1,771.4 $ 1,397.5 $ (1,295.9 ) $ 3,559.1 (a) Includes assets held for sale related to the sale of DPLER. (b) Wholesale revenue for 2014 was not restated for the impact of netting between wholesale revenue and purchased power for the Generation segment because it was impracticable to restate. This impacts the Generation revenue as well as the revenue in the Adjustments and Eliminations column in the table above but has no impact on consolidated revenues or Income / (loss) from continuing operations before income tax. In addition, w holesale revenue for the T&D segment in 2014 includes OVEC revenue of $32.5 million that was previously netted in purchased power. The impact of this netting adjustment is included in the Adjustments and Eliminations column in the table above but has no impact on consolidated revenues or Income / (loss) from continuing operations before income tax. |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Segment Reporting Information [Line Items] | |
Business Segments | Business Segments During the fourth quarter of 2016, DP&L’s management reassessed our separate reportable business segments in connection with recent changes in the regulatory environment, including the pending ESP case, and in preparation for the anticipated transfer of DP&L’s generation assets to AES Ohio Generation. DP&L currently manages the business through two reportable operating segments, the Transmission and Distribution ("T&D") segment and the Generation segment. The primary segment performance measure is income / (loss) from operations before income tax as management has concluded that income / (loss) from operations before income tax best reflects the underlying business performance of DP&L and is the most relevant measure considered in DP&L’s internal evaluation of the financial performance of its segments. The segments are discussed further below: Transmission and Distribution Segment The T&D segment is comprised primarily of DP&L’s electric transmission and distribution businesses, which distribute electricity to residential, commercial, industrial and governmental customers. DP&L distributes electricity to more than 519,000 retail customers who are located in a 6,000 square mile area of West Central Ohio. DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates, and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs. The T&D segment includes revenues and costs associated with our investment in OVEC and the historical results of DP&L’s Beckjord, Hutchings Coal, and East Bend generating facilities, which were either closed or sold in prior periods. As these assets will not be transferring to AES Ohio Generation when DP&L’s planned generation separation occurs, they are grouped with the T&D assets for segment reporting purposes. In addition, regulatory deferrals and collections, which include fuel deferrals in historical periods, are included in the T&D segment. Generation Segment The Generation segment is comprised of DP&L’s electric generation business. Beginning in 2001, Ohio law gave consumers the right to choose the electric generation supplier from whom they purchase retail generation services. DP&L's generation segment owns multiple coal-fired and peaking electric generating facilities. DP&L's generation segment sells its generated energy and capacity into the wholesale market as DP&L sources all of the generation for its SSO customers through a competitive bid process. Prior to the January 1, 2016 DPL sale of DPLER, DP&L also had full requirements sales to DPLER. The accounting policies of the reportable segments are the same as those described in Note 1 – Overview and Summary of Significant Accounting Policies. Intersegment sales and profits are eliminated in consolidation. Certain shared and corporate costs are allocated among reporting segments. The following tables present financial information for each of DP&L’s reportable business segments: $ in millions T&D Generation Adjustments and Eliminations DP&L Total Year ended December 31, 2016 Revenues from external customers $ 808.0 $ 557.9 $ — $ 1,365.9 Intersegment revenues — — — — Total revenues $ 808.0 $ 557.9 $ — $ 1,365.9 Depreciation and amortization $ 71.0 $ 49.3 $ — $ 120.3 Fixed-asset impairment (Note 14) $ — $ 1,353.5 $ — $ 1,353.5 Interest expense $ 24.0 $ 0.5 $ — $ 24.5 Income / (loss) from operations before income tax $ 143.6 $ (1,338.7 ) $ — $ (1,195.1 ) Cash capital expenditures $ 83.4 $ 44.9 $ — $ 128.3 Total assets (end of year) $ 1,710.5 $ 324.6 $ — $ 2,035.1 $ in millions T&D Generation Adjustments and Eliminations DP&L Total Year ended December 31, 2015 Revenues from external customers (a) $ 857.0 $ 715.0 $ (19.7 ) $ 1,552.3 Intersegment revenues — 186.6 (186.6 ) — Total revenues $ 857.0 $ 901.6 $ (206.3 ) $ 1,552.3 Depreciation and amortization $ 71.5 $ 66.7 $ — $ 138.2 Interest expense $ 28.0 $ 2.9 $ — $ 30.9 Income / (loss) from operations before income tax $ 189.0 $ (47.5 ) $ — $ 141.5 Cash capital expenditures $ 98.3 $ 28.7 $ — $ 127.0 Total assets (end of year) $ 1,688.8 $ 1,670.8 $ — $ 3,359.6 (a) Wholesale revenue for the T&D segment in 2015 includes OVEC revenue of $19.7 million that was previously netted in purchased power. The impact of this netting adjustment is included in the Adjustments and Eliminations column in the table above but has no impact on consolidated revenues or Income / (loss) from continuing operations before income tax. $ in millions T&D Generation Adjustments and Eliminations DP&L Total Year ended December 31, 2014 Revenues from external customers (a) $ 1,021.8 $ 679.0 $ (32.5 ) $ 1,668.3 Intersegment revenues — 72.8 (72.8 ) — Total revenues $ 1,021.8 $ 751.8 $ (105.3 ) $ 1,668.3 Depreciation and amortization $ 75.5 $ 69.3 $ — $ 144.8 Interest expense $ 28.9 $ 5.0 $ — $ 33.9 Income / (loss) from operations before income tax $ 242.6 $ (87.9 ) $ — $ 154.7 Cash capital expenditures $ 100.4 $ 13.8 $ — $ 114.2 Total assets (end of year) $ 1,686.1 $ 1,642.7 $ — $ 3,328.8 (a) Wholesale revenue for 2014 was not restated for the impact of netting between wholesale revenue and purchased power for the Generation segment because it was impracticable to restate. This impacts the Generation revenue as well as the revenue in the Adjustments and Eliminations column in the table above but has no impact on consolidated revenues or Income / (loss) from continuing operations before income tax. In addition, w holesale revenue for the T&D segment in 2014 includes OVEC revenue of $32.5 million that was previously netted in purchased power. The impact of this netting adjustment is included in the Adjustments and Eliminations column in the table above but has no impact on consolidated revenues or Income / (loss) from continuing operations before income tax. |
Fixed Asset Impairment
Fixed Asset Impairment | 12 Months Ended |
Dec. 31, 2016 | |
Entity Information [Line Items] | |
Fixed-asset Impairment | Fixed-asset Impairment During the years ended December 31, 2016, 2015 and 2014, DPL had the following fixed-asset impairments: Years ended December 31, Measurement Date 2016 2015 2014 Killen December 31, 2016 $ 75.4 $ — $ — Stuart December 31, 2016 228.5 — — Miami Fort December 31, 2016 149.4 — — Zimmer December 31, 2016 144.7 — — Conesville December 31, 2016 23.9 — — Hutchings peaking facilities December 31, 2016 1.6 — — Killen June 30, 2016 230.8 — — Certain peaking facilities June 30, 2016 4.7 — — East Bend March 31, 2014 — — 11.5 Total impairment loss $ 859.0 $ — $ 11.5 Killen, Stuart, Miami Fort, Zimmer, Conesville and Hutchings, December 31, 2016 - During the fourth quarter of 2016, we tested the recoverability of our long-lived coal-fired generation assets and one gas-fired peaking plant. Additional uncertainty around the useful life of Stuart and Killen related to the DP&L ESP proceedings along with lower expectations of forward dark spreads and capacity prices beyond the cleared period were collectively determined to be an impairment indicator for these assets. Market information indicating that there was a significant decrease in the fair value of Zimmer and Miami Fort was determined to be an indicator of impairment for these assets. The lower forward dark spreads and capacity prices, along with the indicators at the other coal-fired facilities, collectively, resulted in an indicator of impairment for the Conesville asset group. For the gas-fired peaking plant, significant incremental capital expenditures relative to its fair value along with the fact that an impairment charge was previously taken at this facility in Q2 2016, were collectively determined to be an impairment indicator for this asset. DP&L performed a long-lived asset impairment analysis for each of these asset groups and determined that their carrying amounts were not recoverable. The Killen, Stuart, Miami Fort, Zimmer and Conesville coal-fired facility asset groups and the Hutchings gas-fired peaking plant asset group were determined to have a fair value of $42.8 million , $57.4 million , $36.5 million , $23.7 million , $1.1 million and $1.6 million , respectively, using the market approach for Miami Fort and Zimmer and the income approach for the remaining asset groups. As a result, DPL recognized a total pre-tax asset impairment expense of $623.5 million . Killen and DP&L peaking facilities, June 30, 2016 - During the second quarter of 2016, we tested the recoverability of our long-lived assets at certain of our generation facilities at DP&L . A ruling by the Supreme Court of Ohio on June 20, 2016, lower expectation of future capacity revenue resulting from the most recent PJM capacity auction and a higher anticipated level of environmental compliance costs resulting from third party studies were collectively determined to be an impairment indicator for these assets. We performed a long-lived asset impairment analysis and determined that the carrying amounts of Killen and certain DP&L peaking generating facilities were not recoverable. The asset groups of Killen and these DP&L peaking generating facilities were determined to have fair values of $84.3 million and $5.2 million , respectively, using the discounted cash flows under the income approach. As a result, DPL recognized an asset impairment expense of $230.8 million and $4.7 million for Killen and these DP&L peaking generating facilities, respectively. East Bend, March 31, 2014 - During the first quarter of 2014, DPL tested the recoverability of long-lived assets at East Bend, a 186 MW coal-fired plant in Kentucky jointly-owned by DP&L . Indications during that quarter that the fair value of the asset group was less than its carrying amount were determined to be impairment indicators given how narrowly these long-lived assets had passed the recoverability test during the fourth quarter of 2013. DPL performed a long-lived asset impairment test and determined that the carrying amount of the asset group was not recoverable. The East Bend asset group was determined to have a fair value of $2.7 million using the market approach. As a result, we recognized an asset impairment expense of $11.5 million . East Bend is reported in the T&D segment, however, this impairment is shown within Other in Note 14 – Business Segments due to acquisition adjustments at DPL which were not pushed down to the T&D or Generation segments. In May 2014, an agreement was signed for the sale of DP&L’s interest in the generating assets at East Bend. This transaction closed on December 30, 2014. |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Entity Information [Line Items] | |
Fixed-asset Impairment | Fixed-asset Impairment During the years ended December 31, 2016, 2015 and 2014, DP&L had the following fixed-asset impairments: Years ended December 31, Measurement Date 2016 2015 2014 Killen December 31, 2016 $ 75.3 $ — $ — Stuart December 31, 2016 149.9 — — Miami Fort December 31, 2016 157.7 — — Zimmer December 31, 2016 91.3 — — Conesville December 31, 2016 20.8 — — Hutchings peaking facilities December 31, 2016 1.4 — — Stuart June 30, 2016 292.0 — — Killen June 30, 2016 246.2 — — Zimmer June 30, 2016 318.9 — — Total impairment loss $ 1,353.5 $ — $ — Killen, Stuart, Miami Fort, Zimmer, Conesville and Hutchings peakers - December 31, 2016 - During the fourth quarter of 2016, we tested the recoverability of our long-lived coal-fired generation assets and one gas-fired peaking plant. Additional uncertainty around the useful life of Stuart and Killen related to the DP&L ESP proceedings along with lower expectations of forward dark spreads and capacity prices beyond the cleared period were collectively determined to be an impairment indicator for these assets. Market information indicating that there was a significant decrease in the fair value of Zimmer and Miami Fort was determined to be an indicator of impairment for these assets. The lower forward dark spreads and capacity prices, along with the indicators at the other coal-fired facilities, collectively, resulted in an indicator of impairment for the Conesville asset group. For the gas-fired peaking plant, significant incremental capital expenditures relative to its fair value along with the fact that an impairment charge was previously taken at DPL for this facility in Q2 2016, were collectively determined to be an impairment indicator for this asset. DP&L performed a long-lived asset impairment analysis for each of these asset groups and determined that their carrying amounts were not recoverable. The Killen, Stuart, Miami Fort, Zimmer and Conesville coal-fired facility asset groups and the Hutchings gas-fired peaking plant asset group were determined to have a fair value of $42.8 million, $57.4 million, $36.5 million, $23.7 million, $1.1 million and $1.6 million, respectively, using the market approach for Miami Fort and Zimmer and the income approach for the remaining asset groups. As a result, DP&L recognized a total pre-tax asset impairment expense of $496.4 million. Killen, Stuart and Zimmer - June 30, 2016 - During the second quarter of 2016, we tested the recoverability of our long-lived assets at certain of our generation facilities at DP&L . A ruling by the Supreme Court of Ohio on June 20, 2016, lower expectation of future capacity revenue resulting from the most recent PJM capacity auction and a higher anticipated level of environmental compliance costs resulting from third party studies were collectively determined to be an impairment indicator for these assets. We performed a long-lived asset impairment test and determined that the carrying amounts of the asset groups of Stuart, Killen and Zimmer were not recoverable. The asset groups of Stuart, Killen and Zimmer were determined to have fair values of $164.4 million , $84.3 million and $111.0 million , respectively, using the discounted cash flows under the income approach. As a result, DP&L recognized asset impairment expenses of $292.0 million , $246.2 million and $318.9 million for Stuart, Killen and Zimmer, respectively. |
Discontinued Operations
Discontinued Operations | 12 Months Ended |
Dec. 31, 2016 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Discontinued Operations | Discontinued Operations On January 1, 2016, DPL closed on the sale of DPLER, its competitive retail business. The sale agreement was signed on December 28, 2015 and DPL received $75.5 million of restricted cash on December 31, 2015 for the sale. This amount was shown as Restricted cash with the associated liability shown as "Deposit received on sale of DPLER" on the Consolidated Balance Sheet as of December 31, 2015. Assets and liabilities related to DPLER were reclassified to "Assets held for sale" and "Liabilities held for sale" in the December 31, 2015 Consolidated Balance Sheet. DPL recorded a gain on this transaction of $49.2 million in the first quarter of 2016. The gain includes the impact of DPLER’s liability to DP&L that transferred with the sale on January 1, 2016 but was eliminated in consolidation at December 31, 2015. Deferred taxes and intercompany balances were not reclassified to held for sale. Operating activities related to DPLER have been reclassified to "Discontinued operations" in the Consolidated Statements of Operations for the years ended December 31, 2016, 2015 and 2014. The following table summarizes the major categories of assets, liabilities at the dates indicated, and the revenues, cost of revenues, operating expenses and income tax of discontinued operations for the periods indicated: $ in millions December 31, 2015 Accounts receivable, net $ 31.0 Property, plant & equipment, net 1.1 Intangible assets, net 28.1 Other assets 2.0 Total assets of the disposal group classified as held for sale in the balance sheets $ 62.2 Accounts payable $ 0.8 Other liabilities 0.8 Total liabilities of the disposal group classified as held for sale in the balance sheets $ 1.6 Years ended December 31, 2016 2015 2014 Revenues $ — $ 340.9 $ 533.6 Cost of revenues — (307.0 ) (493.0 ) Operating expenses (0.7 ) (22.5 ) (34.0 ) Goodwill impairment — — (135.8 ) Profit / (loss) of discontinued operations before income taxes (0.7 ) 11.4 (129.2 ) Gain from disposal of discontinued operations 49.2 — — Income tax expense / (benefit) 19.2 (1.0 ) 2.6 Income / (loss) on discontinued operations $ 29.3 $ 12.4 $ (131.8 ) DPLER purchased its power from DP&L during the periods presented. Prior to DPLER being presented as a discontinued operation, this purchased power and DP&L's corresponding wholesale revenue would have been eliminated in consolidation. Cash flows related to discontinued operations are included in our Consolidated Statements of Cash Flows. Cash flows from operating activities for discontinued operations were $(0.7) million , $35.8 million and $29.6 million for the years ended December 31, 2016, 2015 and 2014, respectively. Cash flows from investing activities for discontinued operations were $75.5 million , $0.5 million and $(2.2) million for the years ended December 31, 2016, 2015 and 2014, respectively. All cash generated from discontinued operations was paid to DPL through dividends for all years presented. |
Schedule II Valuation And Quali
Schedule II Valuation And Qualifying Accounts | 12 Months Ended |
Dec. 31, 2016 | |
Schedule II Valuation And Qualifying Accounts | Schedule II DPL Inc. VALUATION AND QUALIFYING ACCOUNTS For each of the three years ended December 31, 2016 $ in thousands Description Balance at Beginning of Period Additions Deductions (a) Balance at End of Period Year ended December 31, 2016 Deducted from accounts receivable - Provision for uncollectible accounts (b) $ 835 $ 4,113 $ 3,789 $ 1,159 Deducted from deferred tax assets - Valuation allowance for deferred tax assets $ 17,246 $ — $ 13,921 $ 3,325 Year ended December 31, 2015 Deducted from accounts receivable - Provision for uncollectible accounts (b) $ 898 $ 3,766 $ 3,829 $ 835 Deducted from deferred tax assets - Valuation allowance for deferred tax assets $ 18,900 $ 1,626 $ 3,280 $ 17,246 Year ended December 31, 2014 Deducted from accounts receivable - Provision for uncollectible accounts (b) $ 909 $ 4,011 $ 4,022 $ 898 Deducted from deferred tax assets - Valuation allowance for deferred tax assets $ 13,721 $ 5,179 $ — $ 18,900 (a) Amounts written off, net of recoveries of accounts previously written off (b) Provision for uncollectible accounts related to Company's held-for-sale business as detailed below were excluded from the table above and were included in "Assets held for sale - current" in the consolidated balance sheets. For the years ended, December 31 2015 2014 Beginning balance $ 369 $ 251 Additions 2,035 3,633 Deductions 2,291 3,515 Ending balance $ 113 $ 369 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Schedule II Valuation And Qualifying Accounts | THE DAYTON POWER AND LIGHT COMPANY VALUATION AND QUALIFYING ACCOUNTS For each of the three years ended December 31, 2016 $ in thousands Description Balance at Beginning of Period Additions Deductions (a) Balance at End of Period Year ended December 31, 2016 Deducted from accounts receivable - Provision for uncollectible accounts $ 835 $ 4,113 $ 3,789 $ 1,159 Year ended December 31, 2015 Deducted from accounts receivable - Provision for uncollectible accounts $ 897 $ 3,766 $ 3,828 $ 835 Year ended December 31, 2014 Deducted from accounts receivable - Provision for uncollectible accounts $ 909 $ 4,011 $ 4,023 $ 897 (a) Amounts written off, net of recoveries of accounts previously written off. |
Overview and Summary of Signi28
Overview and Summary of Significant Accounting Policies (Policy) | 12 Months Ended |
Dec. 31, 2016 | |
Significant Accounting Policies [Line Items] | |
Description of Business | Description of Business DPL is a diversified regional energy company organized in 1985 under the laws of Ohio. DPL has two reportable segments, the Transmission and Distribution ("T&D") segment and the Generation segment . See Note 14 – Business Segments for more information relating to reportable segments. The terms “we”, “us”, “our” and “ours” are used to refer to DPL and its subsidiaries. On November 28, 2011, DPL was acquired by AES in the Merger and DPL became a wholly-owned subsidiary of AES. Following the merger of DPL and Dolphin Subsidiary II, Inc., DPL became an indirectly wholly-owned subsidiary of AES. DP&L is a public utility incorporated in 1911 under the laws of Ohio. Beginning in 2001, Ohio law gave Ohio consumers the right to choose the electric generation supplier from whom they purchase retail generation service, however transmission and distribu tion services are still regulated. DP&L has the exclusive right to provide such service to its approximately 519,000 customers located in West Central Ohio. Additionally, DP&L procures and provides retail SSO electric service to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio and generates electricity at five coal-fired power stations. Beginning January 2016, all of the electric supply for SSO customers is competitively bid. Principal industries located in DP&L’s service territory include automotive, food processing, paper, plastic, manufacturing and defense. DP&L's sales reflect the gen eral economic conditions, seasonal weather patterns of the area and the market price of electricity. DP&L sells energy and capacity into the wholesale market. Through December 31, 2015, DP&L's generation was also used to provide electricity to its SSO customers, as it transitioned to a competitive bidding structure in 2014 and 2015, and also sold electricity to DPLER, an affiliate, to satisfy the electric requirements of DPLER's retail customers. On December 30, 2013, DP&L filed an application with the PUCO stating its plan to transfer or sell its generation assets. On July 14, 2014, DP&L announced its decision to retain DP&L’s generation assets. On September 17, 2014, the PUCO ordered that DP&L’s application as amended and updated was approved. DP&L continues to look at multiple options to effectuate the separation, including transfer into an unregulated affiliate of DPL or through a sale. DPLER was sold by DPL on January 1, 2016. DPLER sold competitive retail electric service, under contract, to residential, commercial and industrial customers. DPLER did not own any transmission or generation assets, and it purchased all of its electric energy from DP&L to meet its sales obligations. See Note 16 – Discontinued Operations for more information. DPL’s other significant subsidiaries include AES Ohio Generation, which owns and operates peaking generating facilities from which it makes wholesale sales of electricity, and MVIC, our captive insurance company that provides insurance services to us and our other subsidiaries. DPL owns all of the common stock of its subsidiaries. DPL also has a wholly-owned business trust, DPL Capital Trust II, formed for the purpose of issuing trust capital securities to investors. DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators, while its generation business is deemed competitive under Ohio law. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates, and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs. DPL and its subsidiaries employed 1,168 people at January 31, 2017 , of which 1,160 were employed by DP&L . Approximately 62% of all DPL employees are under a collective bargaining agreement which expires on October 31, 2017 . |
Financial Statement Presentation | We prepare Consolidated Financial Statements for DPL . DPL’s Consolidated Financial Statements include the accounts of DPL and its wholly-owned subsidiaries except for DPL Capital Trust II which is not consolidated, consistent with the provisions of GAAP. DP&L’s undivided ownership interests in certain coal-fired generating stations are included in the financial statements at amortized cost, which was adjusted to fair value at the Merger date. Operating revenues and expenses are included on a pro rata basis in the corresponding lines in the Consolidated Statement of Operations. See Note 4 – Property, Plant and Equipment for more information. All material intercompany accounts and transactions are eliminated in consolidation. We have evaluated subsequent events through the date this report is issued. |
Reclassifications | Certain amounts from prior periods have been reclassified to conform to the current period presentation. See “Intangibles” below for additional information. |
Use of Estimates | The preparation of financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the revenues and expenses of the periods reported. Actual results could differ from these estimates. Significant items subject to such estimates and judgments include: the carrying value of Property, plant and equipment; unbilled revenues; the valuation of derivative instruments; the valuation of insurance and claims liabilities; the valuation of allowances for receivables and deferred income taxes; regulatory assets and liabilities; reserves recorded for income tax exposures; litigation; contingencies; the valuation of AROs; assets and liabilities related to employee benefits; and intangibles. |
Valuation of Goodwill | Valuation of Goodwill FASC 350, “Intangibles – Goodwill and Other”, requires that goodwill be tested for impairment at the reporting unit level at least annually or more frequently if impairment indicators are present. In evaluating the potential impairment of goodwill, we make estimates and assumptions about revenue, operating cash flows, capital expenditures, growth rates and discount rates based on our budgets and long term forecasts, macroeconomic projections, and current market expectations of returns on similar assets. There are inherent uncertainties related to these factors and management’s judgment in applying these factors. Generally, the fair value of a reporting unit is determined using a discounted cash flow valuation model. See Note 7 – Goodwill for information regarding the impairment of goodwill in 2015 and 2014. |
Revenue Recognition | All of the power produced at the generation stations is sold to an RTO and we in turn purchase it back from the RTO to supply our customers. The power sales and purchases within DP&L’s service territory are reported on a net hourly basis as revenues or purchased power on our Consolidated Statements of Operations. We record expenses when purchased electricity is received and when expenses are incurred, with the exception of the ineffective portion of certain power purchase contracts that are derivatives and qualify for hedge accounting. We also have certain derivative contracts that do not qualify for hedge accounting, and their unrealized gains or losses are recorded prior to the receipt of electricity. |
Receivables | We establish provisions for uncollectible accounts by using both historical average loss percentages to project future losses and by establishing specific provisions for known credit issues. Amounts are written off when reasonable collections efforts have been exhausted. |
Property, Plant and Equipment | AFUDC and capitalized interest was $2.8 million , $2.0 million and $1.5 million in the years ended December 31, 2016 , 2015 and 2014 , respectively. For unregulated generation property, cost includes direct labor and material, allocable overhead expenses and interest capitalized during construction using the provisions of GAAP relating to the accounting for capitalized interest. For substantially all depreciable property, when a unit of property is retired, the original cost of that property less any salvage value is charged to Accumulated depreciation and amortization, consistent with composite depreciation practices. Property is evaluated for impairment when events or changes in circumstances indicate that its carrying amount may not be recoverable. See Note 15 – Fixed-asset Impairment for more information. |
Repairs and Maintenance | Costs associated with maintenance activities, primarily power station outages, are recognized at the time the work is performed. These costs, which include labor, materials and supplies, and outside services required to maintain equipment and facilities, are capitalized or expensed based on defined units of property. |
Depreciation - Change in Estimate | Depreciation expense is calculated using the straight-line method, which allocates the cost of property over its estimated useful life. For DPL’s generation, transmission and distribution assets, straight-line depreciation is applied monthly on an average composite basis using group rates that approximated 6.1% in 2016 , 4.4% in 2015 and 5.3% in 2014 . Depreciation expense was $121.9 million , $125.9 million and $128.1 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. |
Regulatory Accounting | The deferral of costs (as regulatory assets) is appropriate only when the future recovery of such costs is probable. In assessing probability, we consider such factors as specific orders from the PUCO or FERC, regulatory precedent and the current regulatory environment. To the extent recovery of costs is no longer deemed probable, related regulatory assets would be required to be expensed in current period earnings. Our regulatory assets and liabilities have been created pursuant to a specific order of the PUCO or FERC or established regulatory practices, such as other utilities under the jurisdiction of the PUCO or FERC being granted recovery of similar costs. It is probable, but not certain, that these regulatory assets will be recoverable, subject to PUCO or FERC approval. Regulatory assets and liabilities are classified as current or non-current based on the term in which recovery is expected. See Note 3 – Regulatory Matters for more information. |
Inventories | Inventories are carried at average cost and include coal, limestone, oil and gas used for electric generation, and materials and supplies used for utility operations. |
Intangibles | Intangible assets include capitalized software of $65.1 million and $59.9 million and its corresponding amortization of $43.2 million and $35.3 million previously classified within Total net property, plant and equipment that were reclassified to Intangible assets as of December 31, 2016 and 2015 , respectively. These assets are amortized over seven years. See “ New Accounting Pronouncements ” below for additional information. A mortization expense was $7.7 million , $9.0 million and $8.6 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. The estimated amortization expense of this internal-use software is $15.3 million ( $6.1 million in 2017, $5.6 million in 2018 and $3.6 million in 2019 ). |
Income Taxes | Consolidated Statement of Operations. Income taxes payable, which are includable in allowable costs for ratemaking purposes in future years, are recorded as regulatory assets with a corresponding deferred tax liability. Investment tax credits that reduced federal income taxes in the years they arose have been deferred and are being amortized to income over the useful lives of the properties in accordance with regulatory treatment. See Note 3 – Regulatory Matters for additional information. DPL and its subsidiaries file U.S. federal income tax returns as part of the consolidated U.S. income tax return filed by AES. The consolidated tax liability is allocated to each subsidiary based on the separate return method which is specified in our tax allocation agreement and which provides a consistent, systematic and rational approach. See Note 9 – Income Taxes for additional information. |
Financial Instruments | We classify our investments in debt and equity financial instruments of publicly traded entities into different categories: held-to-maturity and available-for-sale. Available-for-sale securities are carried at fair value and unrealized gains and losses on those securities, net of deferred income taxes, are presented as a separate component of shareholder's equity. Other-than-temporary declines in value are recognized currently in earnings. Financial instruments classified as held-to-maturity are carried at amortized cost. The cost bases for public equity security and fixed maturity investments are average cost and amortized cost, respectively. |
Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities | The amounts for the years ended December 31, 2016 , 2015 and 2014 , were $50.9 million , $49.9 million and $50.8 million , respectively. |
Cash and Cash Equivalents | Restricted Cash Restricted cash includes cash which is restricted as to withdrawal or usage. The nature of the restrictions includes restrictions imposed by agreements related to deposits held as collateral. At December 31, 2015, restricted cash also includes cash received in connection with the sale of DPLER on January 1, 2016. See Note 16 – Discontinued Operations for additional information regarding the sale of DPLER. |
Financial Derivatives | We use forward contracts to reduce our exposure to changes in energy and commodity prices and as a hedge against the risk of changes in cash flows associated with expected electricity purchases. We hold forward sales contracts that hedge against the risk of changes in cash flows associated with power sales during periods of projected generation facility availability. We use cash flow hedge accounting when the hedge or a portion of the hedge is deemed to be highly effective, which results in changes in fair value being recorded within accumulated other comprehensive income, a component of shareholder’s equity. We have elected not to offset net derivative positions in the financial statements. Accordingly, we do not offset such derivative positions against the fair value of amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral under master netting agreements. See Note 6 – Derivative Instruments and Hedging Activities for additional information. |
Insurance and Claims Costs | In addition to insurance obtained from third-party providers, MVIC, a wholly-owned captive subsidiary of DPL, provides insurance coverage solely to us, our subsidiaries and, in some cases, our partners in commonly-owned facilities we operate, for workers’ compensation, general liability, and property damage on an ongoing basis. MVIC maintains an active run-off policy for directors’ and officers’ liability and fiduciary through their expiration in 2017, which may or may not be renewed at that time. Insurance and Claims Costs on DPL’s Consolidated Balance Sheets associated with MVIC include estimated liabilities of approximately $5.4 million and $5.9 million at December 31, 2016 and 2015 , respectively. In addition, DP&L is responsible for claim costs below certain coverage thresholds of MVIC for the insurance coverage noted above. DP&L has estimated liabilities for medical, life, disability, and other reserves for claims costs below certain coverage thresholds of third-party providers of approximately $12.0 million and $13.7 million at December 31, 2016 and 2015 , respectively, within Other current liabilities and Other deferred credits on the balance sheets. The estimated liabilities for workers’ compensation, medical, life and disability costs at DP&L are actuarially determined using certain assumptions. There is uncertainty associated with these loss estimates and actual results may differ from the estimates. Modification of these loss estimates based on experience and changed circumstances is reflected in the period in which the estimate is re-evaluated. |
Pension and Postretirement Benefits | Consolidated Balance Sheets, an asset or liability reflecting the funded status of pension and other postretirement plans with current-year changes in the funded status recognized in AOCI, except for those portions of our pension and postretirement obligations that can be recovered through future rates. All plan assets are recorded at fair value. We follow the measurement date provisions of the accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans. We account for and disclose pension and postemployment benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postemployment plans. These GAAP provisions require the use of assumptions, such as the discount rate for liabilities and long-term rate of return on assets, in determining the obligations, annual cost, and funding requirements of the plans. Effective January 1, 2016, we applied a disaggregated discount rate approach for determining service cost and interest cost for its defined benefit pension plans and post-retirement plans. This approach is consistent with the requirements of FASC 715 and is considered to be preferential to the aggregated single rate discount approach, which has historically been used in the U.S., because it is more consistent with the philosophy of a full yield curve valuation. The change in discount rate approach did not have an impact on the measurement of the benefit obligations at December 31, 2015 or 2016, nor will it impact future remeasurements. This change in approach impacted the service cost and interest cost recorded in 2016 and will impact future years. It also impacted the actuarial gains and losses recorded in 2016 and will impact future years, as well as the amortization thereof. The 2016 service costs and interest costs included in Note 10 – Benefit Plans reflect the change in methodology described above. The impact of the change in approach on service costs and interest costs in 2016 is shown below: $ in millions 2016 Service Cost 2016 Interest Cost Disaggregated rate approach Aggregate rate approach Impact of change Disaggregated rate approach Aggregate rate approach Impact of change Total Pension $ 5.7 $ 6.1 $ (0.4 ) $ 14.7 $ 17.9 $ (3.2 ) Total Postretirement Benefits 0.2 0.2 — 0.6 0.7 (0.1 ) Total $ 5.9 $ 6.3 $ (0.4 ) $ 15.3 $ 18.6 $ (3.3 ) See Note 10 – Benefit Plans for more information. |
Related Party Transactions | In the normal course of business, DPL enters into transactions with related parties. All material intercompany accounts and transactions are eliminated in DPL’s Consolidated Financial Statements. |
Recently Issued Accounting Standards | New accounting pronouncements The following table provides a brief description of recent accounting pronouncements that could have a material impact on our consolidated financial statements: Accounting Standard Description Date of Adoption Effect on the financial statements upon adoption New Accounting Standards Adopted 2016-19 - Technical Corrections and Improvements This standard clarifies guidance that affects the implementation of ASU 2015-05. It clarifies that the license of internal-use software shall be accounted for as the acquisition of an intangible asset. Transition method: retrospective. December 31, 2016 Capitalized software of $59.9 million and its corresponding amortization of $35.3 million previously classified within property, plant and equipment were reclassified to intangibles as of December 31, 2015. 2015-15, Interest - Imputation of Interest (Subtopic 835-30) Given the absence of authoritative guidance within ASU 2015-03, this standard clarifies that the SEC Staff would not object to an entity presenting debt issuance costs related to line-of-credit arrangements as an asset that is subsequently amortized ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. Transition method: retrospective. January 1, 2016 Deferred financing costs related to lines-of-credit of approximately $3.1 million recorded within Other deferred assets were not reclassified. Accounting Standard Description Date of Adoption Effect on the financial statements upon adoption 2015-03, Interest - Imputation of Interest (Subtopic 835-30) The standard simplifies the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the standard. Transition method: retrospective. January 1, 2016 Deferred financing costs of approximately $2.1 million previously classified within Other prepayments and current assets and $14.0 million previously classified within Other deferred assets were reclassified to reduce the related debt liabilities. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis The standard makes targeted amendments to the current consolidation guidance and ends the deferral granted to investment companies from applying the VIE guidance. The standard amends the evaluation of whether (1) fees paid to a decision-maker or service providers represent a variable interest, (2) a limited partnership or similar entity has the characteristics of a VIE and (3) a reporting entity is the primary beneficiary of a VIE. Transition method: retrospective. January 1, 2016 There were no changes to the consolidation conclusions. 2014-15, “Presentation of Financial Statements - Going Concern (Subtopic 205-40) The standard requires management to evaluate whether there are conditions or events, considered in aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. There are required disclosures if substantial doubt is identified including documentation of principal conditions or events that raised substantial doubt about the entity’s ability to continue as a going concern (before consideration of management’s plans), management’s evaluation of the significance of those conditions or events in relation to the entity’s ability to meet its obligations, and management’s plans that alleviated substantial doubt about the entity’s ability to continue as a going concern. December 31, 2016 Adoption of this standard had no impact on our consolidated financial statements. New Accounting Standards Issued But Not Yet Effective 2017-04, Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment This standard simplifies the accounting for goodwill impairment by removing the requirement to calculate the implied fair value. Instead, it requires that an entity records an impairment charge based on the excess of a reporting unit's carrying amount over its fair value. January 1, 2020. Early adoption is permitted as of January 1, 2017. We are currently evaluating the impact of adopting the standard on our consolidated financial statements. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business This standard provides guidance to assist the entities with evaluating when a set of transferred assets and activities is a business. January 1, 2018. Early adoption is permitted We are currently evaluating the impact of adopting the standard on our consolidated financial statements. 2016-18, Statement of Cash Flows (Topic 320): Restricted Cash (a consensus of the FASB Emerging Issues Task Force) This standard requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. Transition method: retrospective. January 1, 2018 Early adoption is permitted. We are currently evaluating the impact of adopting the standard on our consolidated financial statements. 2016-17, Consolidation (Topic 810): Interest Held Through Related Parties That are Under Common Control States that businesses deciding whether they are primary beneficiaries can consider indirect interests held through related parties that are under common control on a proportionate basis as opposed to in their entirety. January 1, 2017 Early adoption is permitted. Transition is retrospective to all relevant prior periods beginning with the fiscal year in which ASU 2015-02 was initially applied. 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory This standard requires that an entity recognizes the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. Transition method: modified retrospective. January 1, 2018. Early adoption is permitted. We are currently evaluating the impact of adopting the standard on our consolidated financial statements. Accounting Standard Description Date of Adoption Effect on the financial statements upon adoption 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Receipts and Cash Payments (a consensus of the Emerging Issues Task Force) This standard provides specific guidance on how certain cash transactions are presented and classified in the statement of cash flows. Transition method: retrospective. January 1, 2018. Early adoption is permitted. We are currently evaluating the impact of adopting the standard on our consolidated financial statements. We do not anticipate a material effect on our consolidated financial statements. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments The standard updates the impairment model for financial assets measured at amortized cost to an expected loss model rather than an incurred loss model. It also allows for the presentation of credit losses on available-for-sale debt securities as an allowance rather than a write down. Transition method: various. January 1, 2020. Early adoption is permitted only as of January 1, 2019. We are currently evaluating the impact of adopting the standard on our consolidated financial statements. No transition method has been selected yet. 2016-11, Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting Removes some of the Emerging Issues Task Force (EITF) guidance for revenue recognition and hedge accounting from U.S. GAAP to reflect announcements the SEC staff made to the task force in March. January 1, 2018. Earlier application is permitted only as of January 1, 2017. We are currently evaluating the impact of adopting the standard on our consolidated financial statements. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting The standard simplifies the following aspects of accounting for share-based payment awards: accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, statutory tax withholding requirements, classification of awards as either equity or liabilities and classification of employee taxes paid on statement of cash flows when an employer withholds shares for tax-withholding purposes. Transition method: The recording of excess tax benefits and tax deficiencies arising from vesting or settlement will be applied prospectively. The elimination of the requirement that excess tax benefits be realized before they are recognized will be adopted on a modified retrospective basis with a cumulative adjustment to the opening balance sheet. January 1, 2017. Early adoption is permitted. The primary effect of adoption will be the recognition of excess tax benefits in our provision for income taxes in the period when the awards vest or are settled, rather than in paid-in-capital in the period when the excess tax benefits are realized. We will continue to estimate the number of awards that are expected to vest in our determination of the related periodic compensation cost. 2016-06, Derivatives and Hedging (Topic 815) - Contingent Put and Call Options in Debt Instruments This standard clarifies the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. When a call (put) option is contingently exercisable, an entity no longer has to assess whether the event that triggers the ability to exercise a call (put) option is related to interest rates or credit risks. Transition method: a modified retrospective basis to existing debt instruments as of the effective date. January 1, 2017. Early adoption is permitted. We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact on our consolidated financial statements. 2016-05, Derivatives and Hedging (Topic 815) - Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships The standard clarifies that a change in the counterparty to a derivative instrument that has been designated as the hedging instrument under Topic 815 does not require de-designation of that hedging relationship provided that all other hedge accounting criteria (including those in paragraphs 815-20-35-14 through 35-18) continue to be met. Transition method: prospective or a modified retrospective basis. January 1, 2017. Early adoption is permitted. We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact on our consolidated financial statements. No transition method has been selected yet. Accounting Standard Description Date of Adoption Effect on the financial statements upon adoption 2016-02, Leases (Topic 842) The standard creates Topic 842, Leases which supersedes Topic 840, Leases, and introduces a lessee model that brings substantially all leases onto the balance sheet while retaining most of the principles of the existing lessor model in U.S. GAAP and aligning many of those principles with Topic 606, Revenue from Contracts with Customers. Transition method: modified retrospective approach with certain practical expedients. January 1, 2019. Early adoption is permitted. We are currently evaluating the impact of adopting the standard on our consolidated financial statements. 2016-01, Financial Instruments - Overall (Topic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities The standard significantly revises an entity’s accounting related to (1) the classification and measurement of investments in equity securities and (2) the presentation of certain fair value changes for financial liabilities measured at fair value. Also, it amends certain disclosure requirements associated with the fair value of financial instruments. Transition: cumulative effect in Retained Earnings as of adoption or prospectively for equity investments without readily determinable fair value. January 1, 2018. Limited early adoption permitted. We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact on our consolidated financial statements. 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory The standard replaces the current lower of cost or market test with a lower of cost or net realizable value test. Transition method: prospectively. January 1, 2017. Early adoption is permitted. We are currently evaluating the impact of adopting the standard on our consolidated financial statements. 2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, Revenue from Contracts with Customers (Topic 606), See discussion of the ASU below. January 1, 2018. Earlier application is permitted only as of January 1, 2017. We will adopt the standards on January 1, 2018; and we are currently evaluating the effect of their adoption on our consolidated financial statements. ASU 2014-09 and its subsequent corresponding updates provide the principles an entity must apply to measure and recognize revenue. The core principle is that an entity shall recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Amendments to the standard were issued that provide further clarification of the principle and to provide certain transition expedients. The standard will replace most existing revenue recognition guidance in GAAP, including the guidance on recognizing other income upon the sale or transfer of nonfinancial assets (including in-substance real estate). The standard requires retrospective application and allows either a full retrospective adoption in which all of the periods are presented under the new standard or a modified retrospective approach in which the cumulative effect of initially applying the guidance is recognized at the date of initial application. We are currently working towards adopting the standard using the full retrospective method. However, we will continue to assess this conclusion which is dependent on the final impact to the financial statements. In 2016, we established a cross-functional implementation team and are in the process of evaluating changes to our business processes, systems and controls to support recognition and disclosure under the new standard. We are currently evaluating certain contracts along with our tariff revenue, capacity agreements with PJM and wholesale agreements with PJM. We expect additional contracts to be executed during 2017 that will require assessment under the new standard. Through this assessment, we have identified certain key issues that we are continuing to evaluate in order to complete our assessment of the full population of contracts and be able to assess the overall impact to the financial statements. These issues include: the application of the practical expedient for measuring progress toward satisfaction of a performance obligation, when variable quantities would be considered variable consideration versus an option to acquire additional goods and services, and how to measure progress toward completion for a performance obligation that is a bundle. We are continuing to work with various non-authoritative industry groups, and monitoring the FASB and Transition Resource Group (TRG) activity, as we finalize our accounting policy on these and other industry specific interpretative issues which are expected in 2017. |
Master Trust [Member] | |
Significant Accounting Policies [Line Items] | |
Financial Instruments | DPL Capital Trust II DPL has a wholly-owned business trust, DPL Capital Trust II (the Trust), formed for the purpose of issuing trust capital securities to third-party investors. Effective in 2003, DPL deconsolidated the Trust upon adoption of the accounting standards related to variable interest entities and currently treats the Trust as a nonconsolidated subsidiary. The Trust holds mandatorily redeemable trust capital securities. The investment in the Trust, which amounts to $0.3 million and $0.3 million at December 31, 2016 and 2015 , respectively, is included in Other deferred assets within Other noncurrent assets. DPL also has a note payable to the Trust amounting to $15.6 million and $15.6 million at December 31, 2016 and December 31, 2015 , respectively, that was established upon the Trust’s deconsolidation in 2003. See Note 8 – Debt for additional information. In addition to the obligations under the note payable mentioned above, DPL also agreed to a security obligation which represents a full and unconditional guarantee of payments to the capital security holders of the Trust. |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Significant Accounting Policies [Line Items] | |
Description of Business | 519,000 customers located in West Central Ohio. Additionally, DP&L procures and provides retail SSO electric service to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio and generates electricity at five coal-fired power stations. Beginning January 2016, all of the electric supply for SSO customers is competitively bid. Principal industries located in DP&L’s service territory include automotive, food processing, paper, plastic, manufacturing and defense. DP&L's sales reflect the gen eral economic conditions, seasonal weather patterns of the area and the market price of electricity. DP&L sells energy and capacity into the wholesale market. Through December 31, 2015, DP&L's generation was also used to provide electricity to its SSO customers, as it transitioned to a competitive bidding structure in 2014 and 2015, and also sold electricity to DPLER, an affiliate, to satisfy the electric requirements of DPLER's retail customers. DP&L has two segments, the T&D segment and the Generation segment. See Note 13 – Business Segments for more information relating to reportable segments. On December 30, 2013, DP&L filed an application with the PUCO stating its plan to transfer or sell its generation assets. On July 14, 2014, DP&L announced its decision to retain DP&L’s generation assets. On September 17, 2014, the PUCO ordered that DP&L’s application as amended and updated was approved. DP&L continues to look at multiple options to effectuate the separation, including transfer into an unregulated affiliate of DPL or through a sale. DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators, while its generation business is deemed competitive under Ohio law. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates, and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs. DP&L employed 1,160 people at January 31, 2017 . Approximately 63% of all employees are under a collective bargaining agreement which expires on October 31, 2017 . |
Financial Statement Presentation | DP&L does not have any subsidiaries. DP&L has undivided ownership interests in five electric generating facilities and numerous transmission facilities. These undivided interests in jointly-owned facilities are accounted for on a pro rata basis in DP&L’s Financial Statements. We have evaluated subsequent events through the date this report is issued. |
Reclassifications | Certain amounts from prior periods have been reclassified to conform to the current period presentation. See “Intangibles” below for additional information. |
Use of Estimates | The preparation of financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the revenues and expenses of the periods reported. Actual results could differ from these estimates. Significant items subject to such estimates and judgments include: the carrying value of Property, plant and equipment; unbilled revenues; the valuation of derivative instruments; the valuation of insurance and claims liabilities; the valuation of allowances for receivables and deferred income taxes; regulatory assets and liabilities; reserves recorded for income tax exposures; litigation; contingencies; the valuation of AROs; and assets and liabilities related to employee benefits. |
Revenue Recognition | All of the power produced at the generation stations is sold to an RTO and we in turn purchase it back from the RTO to supply our customers. The power sales and purchases within DP&L’s service territory are reported on a net hourly basis as revenues or purchased power on our Statements of Operations. We record expenses when purchased electricity is received and when expenses are incurred, with the exception of the ineffective portion of certain power purchase contracts that are derivatives and qualify for hedge accounting. We also have certain derivative contracts that do not qualify for hedge accounting, and their unrealized gains or losses are recorded prior to the receipt of electricity. |
Receivables | We establish provisions for uncollectible accounts by using both historical average loss percentages to project future losses and by establishing specific provisions for known credit issues. Amounts are written off when reasonable collections efforts have been exhausted. |
Property, Plant and Equipment | AFUDC and capitalized interest was $2.7 million , $2.0 million , and $1.5 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. For unregulated generation property, cost includes direct labor and material, allocable overhead expenses and interest capitalized during construction using the provisions of GAAP relating to the accounting for capitalized interest. For substantially all depreciable property, when a unit of property is retired, the original cost of that property less any salvage value is charged to Accumulated depreciation and amortization, consistent with composite depreciation practices. Property is evaluated for impairment when events or changes in circumstances indicate that its carrying amount may not be recoverable. |
Repairs and Maintenance | Costs associated with maintenance activities, primarily power station outages, are recognized at the time the work is performed. These costs, which include labor, materials and supplies, and outside services required to maintain equipment and facilities, are capitalized or expensed based on defined units of property. |
Depreciation - Change in Estimate | Depreciation expense is calculated using the straight-line method, which allocates the cost of property over its estimated useful life. For DP&L’s generation, transmission and distribution assets, straight-line depreciation is applied monthly on an average composite basis using group rates. For DP&L’s generation, transmission, and distribution assets, straight-line depreciation is applied on an average annual composite basis using group rates that approximated 4.6% in 2016 , 2.5% in 2015 and 2.8% in 2014 . Depreciation was $110.0 million , $132.7 million and $141.6 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. During the fourth quarter of 2015, DP&L tested the recoverability of long-lived assets at certain generating stations. See Note 12 – Related Party Transactions for more information. Gradual decreases in power prices as well as lower estimates of future capacity prices in conjunction with the DP&L reporting unit of DPL failing step 1 of the annual goodwill impairment test were collectively determined to be an impairment indicator. |
Regulatory Accounting | The deferral of costs (as regulatory assets) is appropriate only when the future recovery of such costs is probable. In assessing probability, we consider such factors as specific orders from the PUCO or FERC, regulatory precedent and the current regulatory environment. To the extent recovery of costs is no longer deemed probable, related regulatory assets would be required to be expensed in current period earnings. Our regulatory assets and liabilities have been created pursuant to a specific order of the PUCO or FERC or established regulatory practices, such as other utilities under the jurisdiction of the PUCO or FERC being granted recovery of similar costs. It is probable, but not certain, that these regulatory assets will be recoverable, subject to PUCO or FERC approval. Regulatory assets and liabilities are classified as current or non-current based on the term in which recovery is expected. See Note 3 – Regulatory Matters for more information. |
Inventories | Inventories are carried at average cost and include coal, limestone, oil and gas used for electric generation, and materials and supplies used for utility operations. |
Intangibles | Intangible assets include capitalized software of $78.5 million and $73.9 million and its corresponding amortization of $56.4 million and $49.2 million previously classified within Total net property, plant and equipment that were reclassified to Intangible assets as of December 31, 2016 and 2015 , respectively. These assets are amortized over seven years. See “ New Accounting Pronouncements ” below for additional information. A mortization expense was $7.5 million , $8.2 million and $8.0 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. The estimated amortization expense of this internal-use software is $15.3 million ( $6.1 million in 2017, $5.6 million in 2018 and $3.6 million in 2019 ). |
Income Taxes | Statement of Operations. Income taxes payable, which are includable in allowable costs for ratemaking purposes in future years, are recorded as regulatory assets with a corresponding deferred tax liability. Investment tax credits that reduced federal income taxes in the years they arose have been deferred and are being amortized to income over the useful lives of the properties in accordance with regulatory treatment. See Note 3 – Regulatory Matters for additional information. DPL and its subsidiaries file U.S. federal income tax returns as part of the consolidated U.S. income tax return filed by AES. The consolidated tax liability is allocated to each subsidiary based on the separate return method which is specified in our tax allocation agreement and which provides a consistent, systematic and rational approach. See Note 8 – Income Taxes for additional information. |
Financial Instruments | We classify our investments in debt and equity financial instruments of publicly traded entities into different categories: held-to-maturity and available-for-sale. Available-for-sale securities are carried at fair value and unrealized gains and losses on those securities, net of deferred income taxes, are presented as a separate component of shareholder's equity. Other-than-temporary declines in value are recognized currently in earnings. Financial instruments classified as held-to-maturity are carried at amortized cost. The cost bases for public equity security and fixed maturity investments are average cost and amortized cost, respectively. |
Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities | The amounts for the years ended December 31, 2016 , 2015 and 2014 were $50.9 million , $49.9 million and $50.8 million , respectively. |
Cash and Cash Equivalents | Restricted Cash Restricted cash includes cash which is restricted as to withdrawal or usage. The nature of the restrictions includes restrictions imposed by agreements related to deposits held as collateral. At December 31, 2015, restricted cash also includes cash received in connection with the January 1, 2016 contract termination canceling DP&L's power sales contracts with DPLER. |
Financial Derivatives | We use forward contracts to reduce our exposure to changes in energy and commodity prices and as a hedge against the risk of changes in cash flows associated with expected electricity purchases. We hold forward sales contracts that hedge against the risk of changes in cash flows associated with power sales during periods of projected generation facility availability. We use cash flow hedge accounting when the hedge or a portion of the hedge is deemed to be highly effective, which results in changes in fair value being recorded within accumulated other comprehensive income, a component of shareholder’s equity. We have elected not to offset net derivative positions in the financial statements. Accordingly, we do not offset such derivative positions against the fair value of amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral under master netting agreements. See Note 6 – Derivative Instruments and Hedging Activities for additional information. |
Insurance and Claims Costs | In addition to insurance obtained from third-party providers, MVIC, a wholly-owned captive subsidiary of DPL, provides insurance coverage solely to us, other DPL subsidiaries and, in some cases, our partners in commonly-owned facilities we operate, for workers’ compensation, general liability, and property damage on an ongoing basis. MVIC maintains an active run-off policy for directors’ and officers’ liability and fiduciary through their expiration in 2017, which may or may not be renewed at that time. DP&L is responsible for claim costs below certain coverage thresholds of MVIC and third party insurers for the insurance coverage noted above. DP&L has estimated liabilities for medical, life, disability, and other reserves for claims costs below certain coverage thresholds of MVIC and third-party providers. We recorded these additional insurance and claims costs of approximately $11.8 million and $13.7 million at December 31, 2016 and 2015 , respectively, within Other current liabilities and Other deferred credits on the balance sheets. The estimated liabilities for workers’ compensation, medical, life and disability costs at DP&L are actuarially determined using certain assumptions. There is uncertainty associated with these loss estimates and actual results may differ from the estimates. Modification of these loss estimates based on experience and changed circumstances is reflected in the period in which the estimate is re-evaluated. |
Pension and Postretirement Benefits | We account for and disclose pension and postemployment benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postemployment plans. These GAAP provisions require the use of assumptions, such as the discount rate for liabilities and long-term rate of return on assets, in determining the obligations, annual cost, and funding requirements of the plans. Effective January 1, 2016, we applied a disaggregated discount rate approach for determining service cost and interest cost for its defined benefit pension plans and post-retirement plans. This approach is consistent with the requirements of FASC 715 and is considered to be preferential to the aggregated single rate discount approach, which has historically been used in the U.S., because it is more consistent with the philosophy of a full yield curve valuation. The change in discount rate approach did not have an impact on the measurement of the benefit obligations at December 31, 2015 or 2016, nor will it impact future remeasurements. This change in approach impacted the service cost and interest cost recorded in 2016 and will impact future years. It also impacted the actuarial gains and losses recorded in 2016 and will impact future years, as well as the amortization thereof. The 2016 service costs and interest costs included in Note 9 – Benefit Plans reflect the change in methodology described above. The impact of the change in approach on service costs and interest costs in 2016 is shown below: $ in millions 2016 Service Cost 2016 Interest Cost Disaggregated rate approach Aggregate rate approach Impact of change Disaggregated rate approach Aggregate rate approach Impact of change Total Pension $ 5.7 $ 6.1 $ (0.4 ) $ 14.7 $ 17.9 $ (3.2 ) Total Postretirement Benefits 0.2 0.2 — 0.6 0.7 (0.1 ) Total $ 5.9 $ 6.3 $ (0.4 ) $ 15.3 $ 18.6 $ (3.3 ) See Note 9 – Benefit Plans for more information. |
Related Party Transactions | In the normal course of business, DP&L enters into transactions with other subsidiaries of DPL or AES. See Note 12 – Related Party Transactions for additional information on Related Party Transactions |
Recently Issued Accounting Standards | New accounting pronouncements The following table provides a brief description of recent accounting pronouncements that could have a material impact on our financial statements: Accounting Standard Description Date of Adoption Effect on the financial statements upon adoption New Accounting Standards Adopted 2016-19 - Technical Corrections and Improvements This standard clarifies guidance that affects the implementation of ASU 2015-05. It clarifies that the license of internal-use software shall be accounted for as the acquisition of an intangible asset. Transition method: retrospective. December 31, 2016 Capitalized software of $78.5 million and its corresponding amortization of $56.4 million previously classified within property, plant and equipment were reclassified to intangibles as of December 31, 2016. 2015-15, Interest - Imputation of Interest (Subtopic 835-30) Given the absence of authoritative guidance within ASU 2015-03, this standard clarifies that the SEC Staff would not object to an entity presenting debt issuance costs related to line-of-credit arrangements as an asset that is subsequently amortized ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. Transition method: retrospective. January 1, 2016 Deferred financing costs related to lines-of-credit of approximately $0.7 million recorded within Other deferred assets were not reclassified. 2015-03, Interest - Imputation of Interest (Subtopic 835-30) The standard simplifies the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the standard. Transition method: retrospective. January 1, 2016 Deferred financing costs of approximately $1.8 million previously classified within Other prepayments and current assets and $4.5 million previously classified within Other deferred assets were reclassified to reduce the related debt liabilities. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis The standard makes targeted amendments to the current consolidation guidance and ends the deferral granted to investment companies from applying the VIE guidance. The standard amends the evaluation of whether (1) fees paid to a decision-maker or service providers represent a variable interest, (2) a limited partnership or similar entity has the characteristics of a VIE and (3) a reporting entity is the primary beneficiary of a VIE. Transition method: retrospective. January 1, 2016 There were no changes to the consolidation conclusions. 2014-15, “Presentation of Financial Statements - Going Concern (Subtopic 205-40) The standard requires management to evaluate whether there are conditions or events, considered in aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. There are required disclosures if substantial doubt is identified including documentation of principal conditions or events that raised substantial doubt about the entity’s ability to continue as a going concern (before consideration of management’s plans), management’s evaluation of the significance of those conditions or events in relation to the entity’s ability to meet its obligations, and management’s plans that alleviated substantial doubt about the entity’s ability to continue as a going concern. December 31, 2016 Adoption of this standard had no impact on our financial statements. Accounting Standard Description Date of Adoption Effect on the financial statements upon adoption New Accounting Standards Issued But Not Yet Effective 2017-04, Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment This standard simplifies the accounting for goodwill impairment by removing the requirement to calculate the implied fair value. Instead, it requires that an entity records an impairment charge based on the excess of a reporting unit's carrying amount over its fair value. January 1, 2020. Early adoption is permitted as of January 1, 2017. We are currently evaluating the impact of adopting the standard on our financial statements. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business This standard provides guidance to assist the entities with evaluating when a set of transferred assets and activities is a business. January 1, 2018. Early adoption is permitted We are currently evaluating the impact of adopting the standard on our financial statements. 2016-18, Statement of Cash Flows (Topic 320): Restricted Cash (a consensus of the FASB Emerging Issues Task Force) This standard requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. Transition method: retrospective. January 1, 2018 Early adoption is permitted. We are currently evaluating the impact of adopting the standard on our financial statements. 2016-17, Consolidation (Topic 810): Interest Held Through Related Parties That are Under Common Control States that businesses deciding whether they are primary beneficiaries can consider indirect interests held through related parties that are under common control on a proportionate basis as opposed to in their entirety. January 1, 2017 Early adoption is permitted. Transition is retrospective to all relevant prior periods beginning with the fiscal year in which ASU 2015-02 was initially applied. 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory This standard requires that an entity recognizes the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. Transition method: modified retrospective. January 1, 2018. Early adoption is permitted. We are currently evaluating the impact of adopting the standard on our financial statements. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Receipts and Cash Payments (a consensus of the Emerging Issues Task Force) This standard provides specific guidance on how certain cash transactions are presented and classified in the statement of cash flows. Transition method: retrospective. January 1, 2018. Early adoption is permitted. We are currently evaluating the impact of adopting the standard on our financial statements. We do not anticipate a material effect on our financial statements. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments The standard updates the impairment model for financial assets measured at amortized cost to an expected loss model rather than an incurred loss model. It also allows for the presentation of credit losses on available-for-sale debt securities as an allowance rather than a write down. Transition method: various. January 1, 2020. Early adoption is permitted only as of January 1, 2019. We are currently evaluating the impact of adopting the standard on our financial statements. No transition method has been selected yet. 2016-11, Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting Removes some of the Emerging Issues Task Force (EITF) guidance for revenue recognition and hedge accounting from U.S. GAAP to reflect announcements the SEC staff made to the task force in March. January 1, 2018. Earlier application is permitted only as of January 1, 2017. We are currently evaluating the impact of adopting the standard on our financial statements. Accounting Standard Description Date of Adoption Effect on the financial statements upon adoption 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting The standard simplifies the following aspects of accounting for share-based payment awards: accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, statutory tax withholding requirements, classification of awards as either equity or liabilities and classification of employee taxes paid on statement of cash flows when an employer withholds shares for tax-withholding purposes. Transition method: The recording of excess tax benefits and tax deficiencies arising from vesting or settlement will be applied prospectively. The elimination of the requirement that excess tax benefits be realized before they are recognized will be adopted on a modified retrospective basis with a cumulative adjustment to the opening balance sheet. January 1, 2017. Early adoption is permitted. The primary effect of adoption will be the recognition of excess tax benefits in our provision for income taxes in the period when the awards vest or are settled, rather than in paid-in-capital in the period when the excess tax benefits are realized. We will continue to estimate the number of awards that are expected to vest in our determination of the related periodic compensation cost. 2016-06, Derivatives and Hedging (Topic 815) - Contingent Put and Call Options in Debt Instruments This standard clarifies the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. When a call (put) option is contingently exercisable, an entity no longer has to assess whether the event that triggers the ability to exercise a call (put) option is related to interest rates or credit risks. Transition method: a modified retrospective basis to existing debt instruments as of the effective date. January 1, 2017. Early adoption is permitted. We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact on our financial statements. 2016-05, Derivatives and Hedging (Topic 815) - Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships The standard clarifies that a change in the counterparty to a derivative instrument that has been designated as the hedging instrument under Topic 815 does not require de-designation of that hedging relationship provided that all other hedge accounting criteria (including those in paragraphs 815-20-35-14 through 35-18) continue to be met. Transition method: prospective or a modified retrospective basis. January 1, 2017. Early adoption is permitted. We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact on our financial statements. No transition method has been selected yet. 2016-02, Leases (Topic 842) The standard creates Topic 842, Leases which supersedes Topic 840, Leases, and introduces a lessee model that brings substantially all leases onto the balance sheet while retaining most of the principles of the existing lessor model in U.S. GAAP and aligning many of those principles with Topic 606, Revenue from Contracts with Customers. Transition method: modified retrospective approach with certain practical expedients. January 1, 2019. Early adoption is permitted. We are currently evaluating the impact of adopting the standard on our financial statements. 2016-01, Financial Instruments - Overall (Topic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities The standard significantly revises an entity’s accounting related to (1) the classification and measurement of investments in equity securities and (2) the presentation of certain fair value changes for financial liabilities measured at fair value. Also, it amends certain disclosure requirements associated with the fair value of financial instruments. Transition: cumulative effect in Retained Earnings as of adoption or prospectively for equity investments without readily determinable fair value. January 1, 2018. Limited early adoption permitted. We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact on our financial statements. 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory The standard replaces the current lower of cost or market test with a lower of cost or net realizable value test. Transition method: prospectively. January 1, 2017. Early adoption is permitted. We are currently evaluating the impact of adopting the standard on our financial statements. 2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, Revenue from Contracts with Customers (Topic 606), See discussion of the ASU below. January 1, 2018. Earlier application is permitted only as of January 1, 2017. We will adopt the standards on January 1, 2018; and we are currently evaluating the effect of their adoption on our financial statements. ASU 2014-09 and its subsequent corresponding updates provide the principles an entity must apply to measure and recognize revenue. The core principle is that an entity shall recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Amendments to the standard were issued that provide further clarification of the principle and to provide certain transition expedients. The standard will replace most existing revenue recognition guidance in GAAP, including the guidance on recognizing other income upon the sale or transfer of nonfinancial assets (including in-substance real estate). The standard requires retrospective application and allows either a full retrospective adoption in which all of the periods are presented under the new standard or a modified retrospective approach in which the cumulative effect of initially applying the guidance is recognized at the date of initial application. We are currently working towards adopting the standard using the full retrospective method. However, we will continue to assess this conclusion which is dependent on the final impact to the financial statements. In 2016, we established a cross-functional implementation team and are in the process of evaluating changes to our business processes, systems and controls to support recognition and disclosure under the new standard. We are currently evaluating certain contracts along with our tariff revenue, capacity agreements with PJM and wholesale agreements with PJM. We expect additional contracts to be executed during 2017 that will require assessment under the new standard. Through this assessment, we have identified certain key issues that we are continuing to evaluate in order to complete our assessment of the full population of contracts and be able to assess the overall impact to the financial statements. These issues include: the application of the practical expedient for measuring progress toward satisfaction of a performance obligation, when variable quantities would be considered variable consideration versus an option to acquire additional goods and services, and how to measure progress toward completion for a performance obligation that is a bundle. We are continuing to work with various non-authoritative industry groups, and monitoring the FASB and Transition Resource Group (TRG) activity, as we finalize our accounting policy on these and other industry specific interpretative issues which are expected in 2017. |
Overview and Summary of Signi29
Overview and Summary of Significant Accounting Policies Overview and Summary of Significant Accounting Polices (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Schedule of Expected Service and Interest Costs | The 2016 service costs and interest costs included in Note 10 – Benefit Plans reflect the change in methodology described above. The impact of the change in approach on service costs and interest costs in 2016 is shown below: $ in millions 2016 Service Cost 2016 Interest Cost Disaggregated rate approach Aggregate rate approach Impact of change Disaggregated rate approach Aggregate rate approach Impact of change Total Pension $ 5.7 $ 6.1 $ (0.4 ) $ 14.7 $ 17.9 $ (3.2 ) Total Postretirement Benefits 0.2 0.2 — 0.6 0.7 (0.1 ) Total $ 5.9 $ 6.3 $ (0.4 ) $ 15.3 $ 18.6 $ (3.3 ) |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Schedule of Expected Service and Interest Costs | The 2016 service costs and interest costs included in Note 9 – Benefit Plans reflect the change in methodology described above. The impact of the change in approach on service costs and interest costs in 2016 is shown below: $ in millions 2016 Service Cost 2016 Interest Cost Disaggregated rate approach Aggregate rate approach Impact of change Disaggregated rate approach Aggregate rate approach Impact of change Total Pension $ 5.7 $ 6.1 $ (0.4 ) $ 14.7 $ 17.9 $ (3.2 ) Total Postretirement Benefits 0.2 0.2 — 0.6 0.7 (0.1 ) Total $ 5.9 $ 6.3 $ (0.4 ) $ 15.3 $ 18.6 $ (3.3 ) |
Supplemental Financial Inform30
Supplemental Financial Information (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Supplemental Financial Information [Line Items] | |
Schedule of Supplemental Financial Information | December 31, $ in millions 2016 2015 Accounts receivable, net Unbilled revenue $ 43.0 $ 43.3 Customer receivables 73.9 56.4 Amounts due from partners in jointly-owned stations 12.7 16.0 Other 6.7 6.0 Provisions for uncollectible accounts (1.2 ) (0.8 ) Total accounts receivable, net $ 135.1 $ 120.9 Inventories Fuel and limestone $ 38.9 $ 72.2 Plant materials and supplies 36.6 34.9 Other 1.7 2.0 Total inventories, at average cost $ 77.2 $ 109.1 |
Reclassification out of Accumulated Other Comprehensive Income [Table Text Block] | The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the years ended December 31, 2016 , 2015 and 2014 are as follows: Details about Accumulated Other Comprehensive Income / (Loss) Components Affected line item in the Consolidated Statements of Operations Years ended December 31, $ in millions 2016 2015 2014 Gains and losses on Available-for-sale securities activity (Note 5): Other income $ — $ — $ 0.4 Tax expense — — (0.2 ) Net of income taxes — — 0.2 Gains and losses on cash flow hedges (Note 6): Interest Expense (1.0 ) (1.1 ) (1.3 ) Revenue (55.3 ) (18.7 ) 28.4 Purchased power 9.9 4.4 (0.7 ) Total before income taxes (46.4 ) (15.4 ) 26.4 Tax benefit / (expense) 16.7 5.4 (9.5 ) Net of income taxes (29.7 ) (10.0 ) 16.9 Amortization of defined benefit pension items (Note 10): Operations and maintenance 1.6 0.4 — Tax expense (0.6 ) (0.2 ) — Net of income taxes 1.0 0.2 — Total reclassifications for the period, net of income taxes $ (28.7 ) $ (9.8 ) $ 17.1 |
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block] | The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the years ended December 31, 2016 and 2015 are as follows: $ in millions Gains / (losses) on available-for-sale securities Gains / (losses) on cash flow hedges Change in unfunded pension obligation Total Balance at December 31, 2014 $ 0.5 $ 18.5 $ (11.5 ) $ 7.5 Other comprehensive income / (loss) before reclassifications (0.1 ) 18.2 1.6 19.7 Amounts reclassified from accumulated other comprehensive income / (loss) — (10.0 ) 0.2 (9.8 ) Net current period other comprehensive income / (loss) (0.1 ) 8.2 1.8 9.9 Balance at December 31, 2015 0.4 26.7 (9.7 ) 17.4 Other comprehensive income / (loss) before reclassifications 0.2 16.1 (4.7 ) 11.6 Amounts reclassified from accumulated other comprehensive income / (loss) — (29.7 ) 1.0 (28.7 ) Net current period other comprehensive income / (loss) 0.2 (13.6 ) (3.7 ) (17.1 ) Balance at December 31, 2016 $ 0.6 $ 13.1 $ (13.4 ) $ 0.3 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Supplemental Financial Information [Line Items] | |
Schedule of Supplemental Financial Information | Supplemental Financial Information December 31, $ in millions 2016 2015 Accounts receivable, net Unbilled revenue $ 43.0 $ 43.3 Customer receivables 71.2 54.1 Amounts due from partners in jointly-owned stations 12.7 16.0 Other 8.9 6.9 Provisions for uncollectible accounts (1.2 ) (0.8 ) Total accounts receivable, net $ 134.6 $ 119.5 Inventories Fuel and limestone $ 38.8 $ 72.2 Plant materials and supplies 35.3 33.7 Other 1.7 2.1 Total inventories, at average cost $ 75.8 $ 108.0 |
Reclassification out of Accumulated Other Comprehensive Income [Table Text Block] | The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the years ended December 31, 2016 , 2015 and 2014 are as follows: Details about Accumulated Other Comprehensive Income / (Loss) Components Affected line item in the Statements of Operations Years ended December 31, $ in millions 2016 2015 2014 Gains and losses on Available-for-sale securities activity (Note 5): Other income $ — $ — $ 0.4 Tax expense — — (0.2 ) Net of income taxes — — 0.2 Gains and losses on cash flow hedges (Note 6): Interest expense (1.0 ) (1.1 ) (1.1 ) Revenue (55.3 ) (18.7 ) 28.4 Purchased power 9.9 4.4 (0.4 ) Total before income taxes (46.4 ) (15.4 ) 26.9 Tax benefit / (expense) 16.4 5.6 (11.5 ) Net of income taxes (30.0 ) (9.8 ) 15.4 Amortization of defined benefit pension items (Note 9): Operation and maintenance 7.7 5.6 4.1 Tax expense (1.8 ) (1.9 ) (1.4 ) Net of income taxes 5.9 3.7 2.7 Total reclassifications for the period, net of income taxes $ (24.1 ) $ (6.1 ) $ 18.3 |
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block] | The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the years ended December 31, 2016 and 2015 are as follows: $ in millions Gains / (losses) on available-for-sale securities Gains / (losses) on cash flow hedges Change in unfunded pension obligation Total Balance at December 31, 2014 $ 0.7 $ 2.8 $ (45.8 ) $ (42.3 ) Other comprehensive income / (loss) before reclassifications (0.2 ) 18.2 1.7 19.7 Amounts reclassified from accumulated other comprehensive income / (loss) — (9.8 ) 3.7 (6.1 ) Net current period other comprehensive income / (loss) (0.2 ) 8.4 5.4 13.6 Balance at December 31, 2015 0.5 11.2 (40.4 ) (28.7 ) Other comprehensive income / (loss) before reclassifications 0.2 16.1 (6.0 ) 10.3 Amounts reclassified from accumulated other comprehensive income / (loss) — (30.0 ) 5.9 (24.1 ) Net current period other comprehensive income / (loss) 0.2 (13.9 ) (0.1 ) (13.8 ) Balance at December 31, 2016 $ 0.7 $ (2.7 ) $ (40.5 ) $ (42.5 ) |
Regulatory Assets and Liabili31
Regulatory Assets and Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Schedule of Regulatory Assets and Liabilities | The following table presents DPL’s Regulatory assets and liabilities: December 31, $ in millions Type of Recovery Amortization Through 2016 2015 Regulatory assets, current: Fuel and purchased power recovery costs A 2016 $ — $ 13.9 Economic development costs A 2017 0.1 0.5 Total regulatory assets, current 0.1 14.4 Regulatory assets, non-current: Pension benefits B Ongoing 97.6 91.6 Deferred recoverable income taxes B/C Ongoing 35.9 36.4 Unrecovered OVEC charges D Undetermined 21.0 10.5 Fuel costs B Undetermined 15.4 12.7 Unamortized loss on reacquired debt B Various 8.0 9.0 Smart grid and advanced metering infrastructure costs D Undetermined 7.3 7.3 Rate case costs D Undetermined 6.3 1.9 Generation separation costs D Undetermined 5.7 3.9 Retail settlement system costs D Undetermined 3.1 3.1 Consumer education campaign D Undetermined 3.0 3.0 Other miscellaneous D Undetermined 0.6 0.5 Total regulatory assets, non-current 203.9 179.9 Total regulatory assets $ 204.0 $ 194.3 Regulatory liabilities, current: Competitive bidding $ 16.1 $ 9.1 Energy efficiency program 14.1 9.2 Transmission costs 3.3 3.7 Reconciliation rider — 2.1 Other miscellaneous 0.2 0.3 Total regulatory liabilities, current 33.7 24.4 Regulatory liabilities, non-current: Estimated costs of removal - regulated property 126.5 121.8 Postretirement benefits 3.9 5.2 Total regulatory liabilities, non-current 130.4 127.0 Total regulatory liabilities $ 164.1 $ 151.4 A – Recovery of incurred costs plus rate of return. B – Recovery of incurred costs without a rate of return. C – Balance has an offsetting liability resulting in no effect on rate base. D – Recovery not yet determined, but is probable of occurring in future rate proceedings. |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Schedule of Regulatory Assets and Liabilities | The following table presents DP&L’s Regulatory assets and liabilities: December 31, $ in millions Type of Recovery Amortization Through 2016 2015 Regulatory assets, current: Fuel and purchased power recovery costs A 2016 $ — $ 13.9 Economic development costs A 2017 0.1 0.5 Total regulatory assets, current 0.1 14.4 Regulatory assets, non-current: Pension benefits B Ongoing 97.6 91.6 Deferred recoverable income taxes B/C Ongoing 35.9 36.4 Unrecovered OVEC charges D Undetermined 21.0 10.5 Fuel costs B Undetermined 15.4 12.7 Unamortized loss on reacquired debt B Various 8.0 9.0 Smart grid and advanced metering infrastructure costs D Undetermined 7.3 7.3 Rate case costs D Undetermined 6.3 1.9 Generation separation costs D Undetermined 5.7 3.9 Retail settlement system costs D Undetermined 3.1 3.1 Consumer education campaign D Undetermined 3.0 3.0 Other miscellaneous D Undetermined 0.6 0.5 Total regulatory assets, non-current 203.9 179.9 Total regulatory assets $ 204.0 $ 194.3 Regulatory liabilities, current: Competitive bidding $ 16.1 $ 9.1 Energy efficiency program 14.1 9.2 Transmission costs 3.3 3.7 Reconciliation rider — 2.1 Other miscellaneous 0.2 0.3 Total regulatory liabilities, current 33.7 24.4 Regulatory liabilities, non-current: Estimated costs of removal - regulated property 126.5 121.8 Postretirement benefits 3.9 5.2 Total regulatory liabilities, non-current 130.4 127.0 Total regulatory liabilities $ 164.1 $ 151.4 A – Recovery of incurred costs plus rate of return. B – Recovery of incurred costs without a rate of return. C – Balance has an offsetting liability resulting in no effect on rate base. D – Recovery not yet determined, but is probable of occurring in future rate proceedings. |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Property, Plant and Equipment [Line Items] | |
Summary of Property, Plant, and Equipment | The following is a summary of DPL’s Property, plant and equipment with corresponding composite depreciation rates at December 31, 2016 and 2015 : December 31, $ in millions 2016 Composite Rate 2015 Composite Rate Regulated: Transmission $ 247.3 3.9% $ 239.4 3.9% Distribution 1,141.1 4.7% 1,085.7 5.0% General 13.7 7.4% 13.9 7.2% Non-depreciable 63.5 N/A 62.5 N/A Total regulated 1,465.6 1,401.5 Unregulated: Production / Generation 483.2 11.7% 1,413.1 4.2% Other 17.0 8.0% 16.3 12.1% Non-depreciable 19.8 N/A 19.8 N/A Total unregulated 520.0 1,449.2 Total property, plant and equipment in service $ 1,985.6 6.1% $ 2,850.7 4.4% |
Ownership Interests | DP&L’s undivided ownership interest in such facilities at December 31, 2016 , is as follows: DP&L Share DPL Carrying Value Ownership (%) Summer Production Capacity (MW) Gross Plant In Service ($ in millions) Accumulated Depreciation ($ in millions) Construction Work in Process ($ in millions) Jointly-owned production units Conesville - Unit 4 16.5 129 $ — $ — $ — Killen - Unit 2 67.0 402 34 — 2 Miami Fort - Units 7 and 8 36.0 368 27 — 7 Stuart - Units 1 through 4 35.0 808 24 — 23 Zimmer - Unit 1 28.1 371 7 — 9 Transmission (at varying percentages) 43 10 — Total 2,078 $ 135 $ 10 $ 41 |
Changes in the Liability for Generation AROs | Changes in the Liability for Generation AROs $ in millions Balance at December 31, 2014 $ 26.9 Calendar 2015 Additions 40.3 Accretion expense 1.9 Settlements (3.2 ) Balance at December 31, 2015 65.9 Calendar 2016 Additions 70.2 Accretion expense 2.7 Settlements — Balance at December 31, 2016 $ 138.8 |
Changes in the Liability for Transmission and Distribution Asset Removal Costs | Changes in the Liability for Transmission and Distribution Asset Removal Costs $ in millions Balance at December 31, 2014 $ 119.3 Calendar 2015 Additions 24.3 Settlements (21.8 ) Balance at December 31, 2015 121.8 Calendar 2016 Additions 11.7 Settlements (7.0 ) Balance at December 31, 2016 $ 126.5 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Property, Plant and Equipment [Line Items] | |
Summary of Property, Plant, and Equipment | The following is a summary of DP&L’s Property, plant and equipment with corresponding composite depreciation rates at December 31, 2016 and 2015 : December 31, $ in millions 2016 Composite Rate 2015 Composite Rate Regulated: Transmission $ 421.1 2.3% $ 413.7 2.3% Distribution 1,693.5 3.2% 1,639.7 3.3% General 31.6 3.2% 31.6 3.2% Non-depreciable 63.5 N/A 62.5 N/A Total regulated 2,209.7 2,147.5 Unregulated: Production / Generation 173.9 26.2% 3,009.8 2.1% Non-depreciable 15.0 N/A 15.0 N/A Total unregulated 188.9 3,024.8 Total property, plant and equipment in service $ 2,398.6 4.6% $ 5,172.3 2.5% |
Ownership Interests | DP&L’s undivided ownership interest in such facilities at December 31, 2016 , is as follows: DP&L Share DP&L Carrying Value Ownership % Summer Production Capacity (MW) Gross Plant In Service ($ in millions) Accumulated Depreciation ($ in millions) Construction Work in Process ($ in millions) Jointly-owned production units Conesville - Unit 4 16.5 129 $ — $ — $ — Killen - Unit 2 67.0 402 34 — 2 Miami Fort - Units 7 and 8 36.0 368 27 — 7 Stuart - Units 1 through 4 35.0 808 24 — 23 Zimmer - Unit 1 28.1 371 7 — 9 Transmission (at varying percentages) 99 66 — Total 2,078 $ 191 $ 66 $ 41 |
Changes in the Liability for Generation AROs | Changes in the Liability for Generation AROs $ in millions Balance at December 31, 2014 $ 22.9 Calendar 2015 Additions 40.3 Accretion expense 2.1 Settlements (3.2 ) Balance at December 31, 2015 62.1 Calendar 2016 Additions 70.2 Accretion expense 2.9 Settlements — Balance at December 31, 2016 $ 135.2 |
Changes in the Liability for Transmission and Distribution Asset Removal Costs | Changes in the Liability for Transmission and Distribution Asset Removal Costs $ in millions Balance at December 31, 2014 $ 119.3 Calendar 2015 Additions 24.3 Settlements (21.8 ) Balance at December 31, 2015 121.8 Calendar 2016 Additions 11.7 Settlements (7.0 ) Balance at December 31, 2016 $ 126.5 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Entity Information [Line Items] | |
Fair Value and Cost of Non-Derivative Instruments | The table below presents the fair value and cost of our non-derivative instruments at December 31, 2016 and 2015 . See Note 6 – Derivative Instruments and Hedging Activities for the fair values of our derivative instruments. December 31, 2016 December 31, 2015 $ in millions Cost Fair Value Cost Fair Value Assets Money market funds $ 0.4 $ 0.4 $ 0.2 $ 0.2 Equity securities 2.4 3.4 3.0 3.8 Debt securities 4.4 4.4 4.4 4.3 Hedge funds — 0.1 0.4 0.4 Real estate 0.3 0.3 0.3 0.3 Tangible assets 0.1 0.1 — — Total assets $ 7.6 $ 8.7 $ 8.3 $ 9.0 Carrying Value Fair Value Carrying Value Fair Value Liabilities Debt $ 1,858.4 $ 1,907.7 $ 1,993.3 $ 1,975.3 |
Fair Value of Assets and Liabilities Measured on Recurring Basis | The fair value of assets and liabilities at December 31, 2016 and the respective category within the fair value hierarchy for DPL was determined as follows: Assets and Liabilities at Fair Value Level 1 Level 2 Level 3 $ in millions Fair Value at December 31, 2016 (a) Based on Quoted Prices in Active Markets Other observable inputs Unobservable inputs Assets Master trust assets Money market funds $ 0.4 $ 0.4 $ — $ — Equity securities 3.4 — 3.4 — Debt securities 4.4 — 4.4 — Hedge funds 0.1 — 0.1 — Real estate 0.3 — 0.3 — Tangible assets 0.1 — 0.1 — Total Master trust assets 8.7 0.4 8.3 — Derivative assets Forward power contracts 19.5 — 19.5 — Interest rate hedge 1.2 — 1.2 — FTRs 0.1 — — 0.1 Total Derivative assets 20.8 — 20.7 0.1 Total assets $ 29.5 $ 0.4 $ 29.0 $ 0.1 Liabilities FTRs $ — $ — $ — $ — Interest rate hedge 0.7 — 0.7 — Forward power contracts 28.5 — 26.0 2.5 Total derivative liabilities 29.2 — 26.7 2.5 Long-term debt 1,907.7 — 1,889.7 18.0 Total liabilities $ 1,936.9 $ — $ 1,916.4 $ 20.5 (a) Includes credit valuation adjustment. The fair value of assets and liabilities at December 31, 2015 and the respective category within the fair value hierarchy for DPL was determined as follows: Assets and Liabilities at Fair Value Level 1 Level 2 Level 3 $ in millions Fair Value at December 31, 2015 (a) Based on Quoted Prices in Active Markets Other observable inputs Unobservable inputs Assets Master trust assets Money market funds $ 0.2 $ 0.2 $ — $ — Equity securities 3.8 — 3.8 — Debt securities 4.3 — 4.3 — Hedge funds 0.4 — 0.4 — Real estate 0.3 — 0.3 — Total Master trust assets 9.0 0.2 8.8 — Derivative assets Forward power contracts 30.5 — 30.5 — FTRs 0.2 — — 0.2 Total derivative assets 30.7 — 30.5 0.2 Total assets $ 39.7 $ 0.2 $ 39.3 $ 0.2 Liabilities FTRs $ 0.5 $ — $ — $ 0.5 Forward power contracts 27.0 — 23.9 3.1 Total derivative liabilities 27.5 — 23.9 3.6 Long-term debt 1,975.3 — 1,957.2 18.1 Total liabilities $ 2,002.8 $ — $ 1,981.1 $ 21.7 (a) Includes credit valuation adjustment. |
Fair Value Measurements, Nonrecurring | The following table summarizes major categories of assets and liabilities measured at fair value on a nonrecurring basis during the period and their level within the fair value hierarchy: Measurement Carrying Fair Value Gross $ in millions Date Amount Level 1 Level 2 Level 3 Loss Long-lived assets (a) Year ended December 31, 2016 Killen December 31, 2016 $ 118.2 $ — $ — $ 42.8 $ 75.4 Stuart December 31, 2016 $ 285.9 $ — $ — $ 57.4 228.5 Miami Fort December 31, 2016 $ 185.9 $ — $ — $ 36.5 149.4 Zimmer December 31, 2016 $ 168.4 $ — $ — $ 23.7 144.7 Conesville December 31, 2016 $ 25.0 $ — $ — $ 1.1 23.9 Hutchings peaking facilities December 31, 2016 $ 3.2 $ — $ — $ 1.6 1.6 Killen June 30, 2016 $ 315.1 $ — $ — $ 84.3 230.8 Certain peaking facilities June 30, 2016 $ 9.9 $ — $ — $ 5.2 4.7 Total impairment loss $ 859.0 Year ended December 31, 2014 East Bend March 31, 2014 $ 14.2 $ — $ — $ 2.7 $ 11.5 Goodwill (b) Year ended December 31, 2015 DP&L reporting unit December 31, 2015 $ 317.0 $ — $ — $ — $ 317.0 Year ended December 31, 2014 DPLER Reporting unit June 30, 2014 $ 135.8 $ — $ — $ — $ 135.8 (a) See Note 15 – Fixed-asset Impairment for further information (b) See Note 7 – Goodwill for further information |
Fair Value Inputs, Assets, Quantitative Information [Table Text Block] | The following summarizes the significant unobservable inputs used in the Level 3 measurement on a non-recurring basis during the year ended December 31, 2016: $ in millions Measurement date Fair value Valuation technique Unobservable input Range (weighted average) Long-lived assets held and used: Year ended December 31, 2016 Killen December 31, 2016 $ 42.8 Discounted cash flow Annual revenue growth -14.2% to 2.9% (-8.0%) Annual pre-tax operating margin -56.6% to 42.4% (-15.5%) Weighted-average cost of capital 10.0% Stuart December 31, 2016 $ 57.4 Discounted cash flow Annual revenue growth -11.9% to 1.1% (-4.7%) Annual pre-tax operating margin -61.4% to 75.1% (8.0%) Weighted-average cost of capital 10.0% Miami Fort December 31, 2016 $ 36.5 Market value Indicative offer price Zimmer December 31, 2016 $ 23.7 Market value Indicative offer price Conesville December 31, 2016 $ 1.1 Discounted cash flow Annual revenue growth -19.3% to 10.9% (0.6%) Annual pre-tax operating margin -54.3% to 99.4% (20.2%) Weighted-average cost of capital N/A Hutchings peaking facilities December 31, 2016 $ 1.6 Discounted cash flow Annual revenue growth -19.5% to 25.9% (-0.7%) Annual pre-tax operating margin -40.3% to 63.1% (12.1%) Weighted-average cost of capital 7.0% Killen June 30, 2016 $ 84.3 Discounted cash flow Annual revenue growth -11.0% to 13.0% (2.0%) Annual pre-tax operating margin -50.0% to 67.0% (6.0%) Weighted-average cost of capital 11.0% Certain peaking facilities June 30, 2016 $ 5.2 Discounted cash flow Annual revenue growth -22.0% to 17.0% (-3.0%) Annual pre-tax operating margin -29.0% to 24.0% (-4.0%) Weighted-average cost of capital 7.0% |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Entity Information [Line Items] | |
Fair Value and Cost of Non-Derivative Instruments | The table below presents the fair value and cost of our non-derivative instruments at December 31, 2016 and 2015 . See also Note 6 – Derivative Instruments and Hedging Activities for the fair values of our derivative instruments. December 31, 2016 December 31, 2015 $ in millions Cost Fair Value Cost Fair Value Assets Money market funds $ 0.4 $ 0.4 $ 0.2 $ 0.2 Equity securities 2.4 3.4 3.0 3.8 Debt securities 4.4 4.4 4.4 4.3 Hedge funds — 0.1 0.4 0.4 Real estate 0.3 0.3 0.3 0.3 Tangible assets 0.1 0.1 — — Total assets $ 7.6 $ 8.7 $ 8.3 $ 9.0 Carrying Value Fair Value Carrying Value Fair Value Liabilities Debt $ 749.4 $ 763.5 $ 756.7 $ 764.2 |
Fair Value of Assets and Liabilities Measured on Recurring Basis | The fair value of assets and liabilities at December 31, 2016 and the respective category within the fair value hierarchy for DP&L was determined as follows: Assets and Liabilities at Fair Value Level 1 Level 2 Level 3 $ in millions Fair Value at December 31, 2016 (a) Based on Quoted Prices in Active Markets Other observable inputs Unobservable inputs Assets Master trust assets Money market funds $ 0.4 $ 0.4 $ — $ — Equity securities 3.4 — 3.4 — Debt securities 4.4 — 4.4 — Hedge funds 0.1 — 0.1 — Real estate 0.3 — 0.3 — Tangible assets 0.1 — 0.1 — Total Master trust assets 8.7 0.4 8.3 — Derivative assets FTRs 0.1 — — 0.1 Interest rate hedge 1.2 — 1.2 — Forward power contracts 19.5 — 19.5 — Total derivative assets 20.8 — 20.7 0.1 Total assets $ 29.5 $ 0.4 $ 29.0 $ 0.1 Liabilities FTRs $ — $ — $ — $ — Interest rate hedge 0.7 — 0.7 — Forward power contracts 28.5 — 26.0 2.5 Total derivative liabilities 29.2 — 26.7 2.5 Long-term debt 763.5 — 745.5 18.0 Total liabilities $ 792.7 $ — $ 772.2 $ 20.5 (a) Includes credit valuation adjustment. The fair value of assets and liabilities at December 31, 2015 and the respective category within the fair value hierarchy for DP&L was determined as follows: Assets and Liabilities at Fair Value Level 1 Level 2 Level 3 $ in millions Fair Value at December 31, 2015 (a) Based on Quoted Prices in Active Markets Other observable inputs Unobservable inputs Assets Master trust assets Money market funds $ 0.2 $ 0.2 $ — $ — Equity securities 3.8 — 3.8 — Debt securities 4.3 — 4.3 — Hedge funds 0.4 — 0.4 — Real estate 0.3 — 0.3 — Total Master trust assets 9.0 0.2 8.8 — Derivative assets FTRs 0.2 — — 0.2 Forward power contracts 30.6 — 30.6 — Total derivative assets 30.8 — 30.6 0.2 Total assets $ 39.8 $ 0.2 $ 39.4 $ 0.2 Liabilities FTRs $ 0.5 $ — $ — $ 0.5 Forward power contracts 27.0 — 23.9 3.1 Total derivative liabilities 27.5 — 23.9 3.6 Long-term debt 764.2 — 746.1 18.1 Total liabilities $ 791.7 $ — $ 770.0 $ 21.7 (a) Includes credit valuation adjustment. |
Fair Value Measurements, Nonrecurring | The following table summarizes major categories of assets and liabilities measured at fair value on a nonrecurring basis during the period and their level within the fair value hierarchy: Measurement Carrying Fair Value Gross $ in millions Date Amount Level 1 Level 2 Level 3 Loss Long-lived assets (a) Year ended December 31, 2016 Killen December 31, 2016 $ 118.1 $ — $ — $ 42.8 $ 75.3 Stuart December 31, 2016 $ 207.3 $ — $ — $ 57.4 149.9 Miami Fort December 31, 2016 $ 194.2 $ — $ — $ 36.5 157.7 Zimmer December 31, 2016 $ 115.0 $ — $ — $ 23.7 91.3 Conesville December 31, 2016 $ 21.9 $ — $ — $ 1.1 20.8 Hutchings peaking facilities December 31, 2016 $ 3.0 $ — $ — $ 1.6 1.4 Stuart June 30, 2016 $ 456.4 $ — $ — $ 164.4 292.0 Killen June 30, 2016 $ 330.5 $ — $ — $ 84.3 246.2 Zimmer June 30, 2016 $ 429.9 $ — $ — $ 111.0 318.9 Total impairment loss $ 1,353.5 (a) See Note 14 – Fixed-asset Impairment for further information. |
Fair Value Measurements of Plan Assets Using Significant Unobservable Inputs | The following summarizes the significant unobservable inputs used in the Level 3 measurement on a non-recurring basis during the year ended December 31, 2016: $ in millions Measurement date Fair value Valuation technique Unobservable input Range (weighted average) Long-lived assets held and used: Year ended December 31, 2016 Killen December 31, 2016 $ 42.8 Discounted cash flow Annual revenue growth -14.2% to 2.9% (-8.0%) Annual pre-tax operating margin -56.6% to 42.4% (-15.5%) Weighted-average cost of capital 10.0% $ in millions Measurement date Fair value Valuation technique Unobservable input Range (weighted average) Long-lived assets held and used: Year ended December 31, 2016 Stuart December 31, 2016 $ 57.4 Discounted cash flow Annual revenue growth -11.9% to 1.1% (-4.7%) Annual pre-tax operating margin -61.4% to 75.1% (8.0%) Weighted-average cost of capital 10.0% Miami Fort December 31, 2016 $ 36.5 Market value Indicative offer price Zimmer December 31, 2016 $ 23.7 Market value Indicative offer price Conesville December 31, 2016 $ 1.1 Discounted cash flow Annual revenue growth -19.3% to 10.9% (0.6%) Annual pre-tax operating margin -54.3% to 99.4% (20.2%) Weighted-average cost of capital N/A Hutchings peaking facilities December 31, 2016 $ 1.6 Discounted cash flow Annual revenue growth -19.5% to 25.9% (-0.7%) Annual pre-tax operating margin -40.3% to 63.1% (12.1%) Weighted-average cost of capital 7.0% Stuart June 30, 2016 $ 164.4 Discounted cash flow Annual revenue growth -9.0% to 10.0% (2.0%) Annual pre-tax operating margin -29.0% to 52.0% (5.0%) Weighted-average cost of capital 9.0% Killen June 30, 2016 $ 84.3 Discounted cash flow Annual revenue growth -11.0% to 13.0% (2.0%) Annual pre-tax operating margin -50.0% to 67.0% (6.0%) Weighted-average cost of capital 11.0% Zimmer June 30, 2016 $ 111.0 Discounted cash flow Annual revenue growth -14.0% to 13.0% (1.0%) Annual pre-tax operating margin -46.0% to 80.0% (4.0%) Weighted-average cost of capital 9.0% |
Derivative Instruments and He34
Derivative Instruments and Hedging Activities (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Schedule of Notional Amounts of Outstanding Derivative Positions | At December 31, 2016 , DPL had the following outstanding derivative instruments: Commodity Accounting Treatment Unit Purchases (in thousands) Sales (in thousands) Net Purchases/ (Sales) (in thousands) FTRs Not designated MWh 2.3 — 2.3 Natural Gas Not designated Dths 1,590.0 — 1,590.0 Forward Power Contracts Designated MWh 342.9 (9,974.5 ) (9,631.6 ) Forward Power Contracts Not designated MWh 2,568.3 (2,020.9 ) 547.4 Interest Rate Swaps Designated USD 200,000.0 — 200,000.0 At December 31, 2015 , DPL had the following outstanding derivative instruments: Commodity Accounting Treatment Unit Purchases (in thousands) Sales (in thousands) Net Purchases/ (Sales) (in thousands) FTRs Not designated MWh 10.2 — 10.2 Forward Power Contracts Designated MWh 1,676.7 (7,795.8 ) (6,119.1 ) Forward Power Contracts Not designated MWh 5,049.9 (1,663.0 ) 3,386.9 |
Gains or Losses Recognized in AOCI for the Cash Flow Hedges | The following tables set forth the gains / (losses) recognized in AOCI and earnings related to the effective portion of derivative instruments and the gains / (losses) recognized in earnings related to the ineffective portion of derivative instruments in qualifying cash flow hedging relationships, as defined in the accounting standards for derivatives and hedging, for the periods indicated: Years ended December 31, 2016 2015 2014 $ in millions (net of tax) Power Interest Rate Hedges Power Interest Rate Hedges Power Interest Rate Hedges Beginning accumulated derivative gain in AOCI $ 9.2 $ 17.5 $ 0.2 $ 18.3 $ 1.4 $ 19.2 Net gains / (losses) associated with current period hedging transactions 15.7 0.4 18.2 — (19.0 ) — Net gains / (losses) reclassified to earnings: Interest Expense — (0.5 ) — (0.8 ) — (0.9 ) Revenues (35.6 ) — (12.0 ) — 18.3 — Purchased Power 6.4 — 2.8 — (0.5 ) — Ending accumulated derivative gain / (loss) in AOCI $ (4.3 ) $ 17.4 $ 9.2 $ 17.5 $ 0.2 $ 18.3 Net gains or losses associated with the ineffective portion of the hedging transactions were immaterial in the periods presented. Portion expected to be reclassified to earnings in the next twelve months (a) $ (3.5 ) $ (0.5 ) Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) 15 44 (a) The actual amounts that we reclassify from AOCI to earnings related to power can differ from the estimate above due to market price changes. |
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location | The following tables show the amount and classification within the consolidated statements of operations or balance sheets of the gains and losses on DPL’s derivatives not designated as hedging instruments for the years ended December 31, 2016 , 2015 and 2014 : Year ended December 31, 2016 $ in millions Heating Oil FTRs Power Natural Gas Total Derivatives not designated as hedging instruments Change in unrealized gain / (loss) $ — $ 0.3 $ 4.0 $ — $ 4.3 Realized gain / (loss) — (0.6 ) (7.2 ) 2.6 (5.2 ) Total $ — $ (0.3 ) $ (3.2 ) $ 2.6 $ (0.9 ) Recorded on Balance Sheet: Regulatory asset $ — $ — $ — $ — $ — Recorded in Statement of Operations: gain / (loss) Revenue — — (17.3 ) — (17.3 ) Purchased Power — (0.3 ) 14.1 2.6 16.4 Total $ — $ (0.3 ) $ (3.2 ) $ 2.6 $ (0.9 ) Year ended December 31, 2015 $ in millions Heating Oil FTRs Power Natural Gas Total Derivatives not designated as hedging instruments Change in unrealized gain / (loss) $ 0.4 $ 0.3 $ (6.4 ) $ 0.1 $ (5.6 ) Realized gain / (loss) (0.3 ) (0.2 ) (9.8 ) (0.1 ) (10.4 ) Total $ 0.1 $ 0.1 $ (16.2 ) $ — $ (16.0 ) Recorded on Balance Sheet: Regulatory asset $ 0.1 $ — $ — $ — $ 0.1 Recorded in Statement of Operations: gain / (loss) Revenue — — 27.4 — 27.4 Purchased Power — 0.1 (43.6 ) — (43.5 ) Total $ 0.1 $ 0.1 $ (16.2 ) $ — $ (16.0 ) Year ended December 31, 2014 $ in millions Heating Oil FTRs Power Natural Gas Total Derivatives not designated as hedging instruments Change in unrealized gain / (loss) $ (0.6 ) $ (0.8 ) $ (1.5 ) $ (0.1 ) $ (3.0 ) Realized gain / (loss) (0.1 ) 0.7 (3.6 ) (0.1 ) (3.1 ) Total $ (0.7 ) $ (0.1 ) $ (5.1 ) $ (0.2 ) $ (6.1 ) Recorded on Balance Sheet Regulatory asset $ (0.1 ) $ — $ — $ — $ (0.1 ) Recorded in Statement of Operations: gain / (loss) Fuel (0.6 ) — — — (0.6 ) Purchased Power — (0.1 ) (5.1 ) (0.2 ) (5.4 ) Total $ (0.7 ) $ (0.1 ) $ (5.1 ) $ (0.2 ) $ (6.1 ) |
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block] | The following tables show the fair value, balance sheet classification and hedging designation of DPL’s derivative instruments at December 31, 2016 and 2015 . Fair Values of Derivative Instruments December 31, 2016 Gross Amounts Not Offset in the Consolidated Balance Sheets $ in millions Hedging Designation Gross Fair Value as presented in the Consolidated Balance Sheets (a) Financial Instruments with Same Counterparty in Offsetting Position Cash Collateral Net Amount Assets Short-term derivative positions (presented in Other current assets) Forward power contracts Designated $ 11.0 $ (10.5 ) $ — $ 0.5 Forward power contracts Not designated 6.0 (4.7 ) — 1.3 FTRs Not designated 0.1 — — 0.1 Long-term derivative positions (presented in Other deferred assets) Interest Rate Swaps Designated 1.2 — — 1.2 Forward power contracts Designated 0.6 (0.6 ) — — Forward power contracts Not designated 1.9 (1.0 ) — 0.9 Total assets $ 20.8 $ (16.8 ) $ — $ 4.0 Liabilities Short-term derivative positions (presented in Other current liabilities) Interest Rate Swaps Designated $ 0.7 $ — $ — $ 0.7 Forward power contracts Designated $ 16.4 $ (10.5 ) $ (5.5 ) $ 0.4 Forward power contracts Not designated 7.7 (4.7 ) — 3.0 FTRs Not designated — — — — Long-term derivative positions (presented in Other deferred liabilities) Forward power contracts Designated 2.4 (0.6 ) (0.8 ) 1.0 Forward power contracts Not designated 2.0 (1.0 ) — 1.0 Total liabilities $ 29.2 $ (16.8 ) $ (6.3 ) $ 6.1 (a) Includes credit valuation adjustment. Fair Values of Derivative Instruments December 31, 2015 Gross Amounts Not Offset in the Consolidated Balance Sheets $ in millions Hedging Designation Gross Fair Value as presented in the Consolidated Balance Sheets (a) Financial Instruments with Same Counterparty in Offsetting Position Cash Collateral Net Amount Assets Short-term derivative positions (presented in Other current assets) Forward power contracts Designated $ 16.2 $ (7.1 ) $ — $ 9.1 Forward power contracts Not designated 7.3 (5.5 ) — 1.8 FTRs Not designated 0.2 (0.2 ) — — Long-term derivative positions (presented in Other deferred assets) Forward power contracts Designated 3.0 (2.4 ) — 0.6 Forward power contracts Not designated 4.0 (2.7 ) — 1.3 Total assets $ 30.7 $ (17.9 ) $ — $ 12.8 Liabilities Short-term derivative positions (presented in Other current liabilities) Forward power contracts Designated $ 7.1 $ (7.1 ) $ — $ — Forward power contracts Not designated 14.5 (5.5 ) (8.0 ) 1.0 FTRs Not designated 0.5 (0.2 ) — 0.3 Long-term derivative positions (presented in Other deferred liabilities) Forward power contracts Designated 2.7 (2.4 ) — 0.3 Forward power contracts Not designated 2.7 (2.7 ) — — Total liabilities $ 27.5 $ (17.9 ) $ (8.0 ) $ 1.6 (a) Includes credit valuation adjustment. |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Schedule of Notional Amounts of Outstanding Derivative Positions | At December 31, 2016 , DP&L had the following outstanding derivative instruments: Commodity Accounting Treatment Unit Purchases (in thousands) Sales (in thousands) Net Purchases/ (Sales) (in thousands) FTRs Not designated MWh 2.3 — 2.3 Natural Gas Not designated Dths 1,590.0 — 1,590.0 Forward Power Contracts Designated MWh 342.9 (9,974.5 ) (9,631.6 ) Forward Power Contracts Not designated MWh 2,568.3 (2,037.5 ) 530.8 Interest Rate Swaps Designated USD 200,000.0 — 200,000.0 At December 31, 2015 , DP&L had the following outstanding derivative instruments: Commodity Accounting Treatment Unit Purchases (in thousands) Sales (in thousands) Net Purchases/ (Sales) (in thousands) FTRs Not designated MWh 10.2 — 10.2 Forward Power Contracts Designated MWh 1,676.7 (7,795.8 ) (6,119.1 ) Forward Power Contracts Not designated MWh 5,049.9 (1,665.7 ) 3,384.2 |
Gains or Losses Recognized in AOCI for the Cash Flow Hedges | The following tables set forth the gains / (losses) recognized in AOCI and earnings related to the effective portion of derivative instruments and the gains / (losses) recognized in earnings related to the ineffective portion of derivative instruments in qualifying cash flow hedging relationships, as defined in the accounting standards for derivatives and hedging, for the periods indicated: Years ended December 31, 2016 2015 2014 $ in millions (net of tax) Power Interest Rate Hedges Power Interest Rate Hedges Power Interest Rate Hedges Beginning accumulated derivative gain in AOCI $ 9.2 $ 2.0 $ 0.2 $ 2.6 $ 1.0 $ 5.2 Net gains / (losses) associated with current period hedging transactions 15.7 0.4 18.2 — (18.8 ) — Net gains / (losses) reclassified to earnings: Interest Expense — (0.8 ) — (0.6 ) — (2.6 ) Revenues (35.6 ) — (12.0 ) — 18.2 — Purchased Power 6.4 — 2.8 — (0.2 ) — Ending accumulated derivative gain / (loss) in AOCI $ (4.3 ) $ 1.6 $ 9.2 $ 2.0 $ 0.2 $ 2.6 Net gains or losses associated with the ineffective portion of the hedging transactions were immaterial in the periods presented. Portion expected to be reclassified to earnings in the next twelve months (a) $ (3.5 ) $ (0.8 ) Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) 15 44 (a) The actual amounts that we reclassify from AOCI to earnings related to power can differ from the estimate above due to market price changes. |
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location | The following tables show the amount and classification within the statements of operations or balance sheets of the gains and losses on DP&L’s derivatives not designated as hedging instruments for the years ended December 31, 2016 , 2015 and 2014 . Year ended December 31, 2016 $ in millions Heating Oil FTRs Power Natural Gas Total Derivatives not designated as hedging instruments Change in unrealized gain / (loss) $ — $ 0.3 $ 3.9 $ — $ 4.2 Realized gain / (loss) — (0.6 ) (7.9 ) 2.6 (5.9 ) Total $ — $ (0.3 ) $ (4.0 ) $ 2.6 $ (1.7 ) Recorded on Balance Sheet: Regulatory asset $ — $ — $ — $ — $ — Recorded in Statement of Operations: gain / (loss) Revenue — — (18.1 ) — (18.1 ) Purchased Power — (0.3 ) 14.1 2.6 16.4 Total $ — $ (0.3 ) $ (4.0 ) $ 2.6 $ (1.7 ) Year ended December 31, 2015 $ in millions Heating Oil FTRs Power Natural Gas Total Derivatives not designated as hedging instruments Change in unrealized gain / (loss) $ 0.4 $ 0.3 $ (6.3 ) $ 0.1 $ (5.5 ) Realized gain / (loss) (0.3 ) (0.2 ) (9.9 ) (0.1 ) (10.5 ) Total $ 0.1 $ 0.1 $ (16.2 ) $ — $ (16.0 ) Recorded on Balance Sheet: Regulatory asset $ 0.1 $ — $ — $ — $ 0.1 Recorded in Statement of Operations: gain / (loss) Revenue — — 27.4 — 27.4 Purchased Power — 0.1 (43.6 ) — (43.5 ) Total $ 0.1 $ 0.1 $ (16.2 ) $ — $ (16.0 ) Year ended December 31, 2014 $ in millions Heating Oil FTRs Power Natural Gas Total Derivatives not designated as hedging instruments Change in unrealized loss $ (0.6 ) $ (0.8 ) $ (1.5 ) $ (0.1 ) $ (3.0 ) Realized gain / (loss) (0.1 ) 0.7 (3.0 ) (0.1 ) (2.5 ) Total $ (0.7 ) $ (0.1 ) $ (4.5 ) $ (0.2 ) $ (5.5 ) Recorded on Balance Sheet: Regulatory (asset) / liability $ (0.1 ) $ — $ — $ — $ (0.1 ) Recorded in Statement of Operations: gain / (loss) Revenue — — 0.7 — 0.7 Fuel (0.6 ) — — — (0.6 ) Purchased Power — (0.1 ) (5.2 ) (0.2 ) (5.5 ) Total $ (0.7 ) $ (0.1 ) $ (4.5 ) $ (0.2 ) $ (5.5 ) |
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block] | The following tables show the fair value, balance sheet classification and hedging designation of DP&L’s derivative instruments at December 31, 2016 and 2015 . Fair Values of Derivative Instruments December 31, 2016 Gross Amounts Not Offset in the Balance Sheets $ in millions Hedging Designation Gross Fair Value as presented in the Balance Sheets Financial Instruments with Same Counterparty in Offsetting Position Cash Collateral Net Amount Assets Short-term derivative positions (presented in Other current assets) Forward power contracts Designated $ 11.0 $ (10.5 ) $ — $ 0.5 Forward power contracts Not designated 6.0 (4.7 ) — 1.3 FTRs Not designated 0.1 — — 0.1 Long-term derivative positions (presented in Other deferred assets) Forward power contracts Designated 0.6 (0.6 ) — — Interest Rate Swaps Designated 1.2 — — 1.2 Forward power contracts Not designated 1.9 (1.0 ) — 0.9 Total assets $ 20.8 $ (16.8 ) $ — $ 4.0 Liabilities Short-term derivative positions (presented in Other current liabilities) Forward power contracts Designated $ 16.4 $ (10.5 ) $ (5.5 ) $ 0.4 Interest Rate Swaps Designated 0.7 — — 0.7 Forward power contracts Not designated 7.7 (4.7 ) — 3.0 FTRs Not designated — — — — Long-term derivative positions (presented in Other deferred liabilities) Forward power contracts Designated 2.4 (0.6 ) (0.8 ) 1.0 Forward power contracts Not designated 2.0 (1.0 ) — 1.0 Total liabilities $ 29.2 $ (16.8 ) $ (6.3 ) $ 6.1 (a) Includes credit valuation adjustment. Fair Values of Derivative Instruments December 31, 2015 Gross Amounts Not Offset in the Balance Sheets $ in millions Hedging Designation Gross Fair Value as presented in the Balance Sheets Financial Instruments with Same Counterparty in Offsetting Position Cash Collateral Net Amount Assets Short-term derivative positions (presented in Other current assets) Forward power contracts Designated $ 16.2 $ (7.1 ) $ — $ 9.1 Forward power contracts Not designated 7.4 (5.5 ) — 1.9 FTRs Not designated 0.2 (0.2 ) — — Long-term derivative positions (presented in Other deferred assets) Forward power contracts Designated 3.0 (2.4 ) — 0.6 Forward power contracts Not designated 4.0 (2.7 ) — 1.3 Total assets $ 30.8 $ (17.9 ) $ — $ 12.9 Liabilities Short-term derivative positions (presented in Other current liabilities) Forward power contracts Designated $ 7.1 $ (7.1 ) $ — $ — Forward power contracts Not designated 14.5 (5.5 ) (8.0 ) 1.0 FTRs Not designated 0.5 (0.2 ) — 0.3 Long-term derivative positions (presented in Other deferred liabilities) Forward power contracts Designated 2.7 (2.4 ) — 0.3 Forward power contracts Not designated 2.7 (2.7 ) — — Total liabilities $ 27.5 $ (17.9 ) $ (8.0 ) $ 1.6 (a) Includes credit valuation adjustment. |
Goodwill And Other Intangible35
Goodwill And Other Intangible Assets (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Changes in Goodwill | The following table summarizes the changes in Goodwill by reporting unit for the years ended December 31, 2015 and 2014: $ in millions DP&L Reporting Unit Balance at December 31, 2014 Goodwill $ 2,440.5 Accumulated impairment losses (2,123.5 ) Net balance at December 31, 2014 $ 317.0 Goodwill impairments during 2015 $ (317.0 ) Balance at December 31, 2015 Goodwill $ 2,440.5 Accumulated impairment losses (2,440.5 ) Net balance at December 31, 2015 $ — |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Debt Instrument [Line Items] | |
Long-term Debt | Long-term debt $ in millions Interest Rate Maturity December 31, 2016 December 31, 2015 Term loan - rates from: 4.00% - 4.01% (a) 2022 $ 445.0 $ — First Mortgage Bonds 1.875% — 445.0 Tax-exempt First Mortgage Bonds 4.8% 2036 100.0 100.0 Tax-exempt First Mortgage Bonds - rates from: 1.29% - 1.42% (a) and 1.13% - 1.17% (b) 2020 200.0 200.0 U.S. Government note 4.2% 2061 18.0 18.1 Capital leases 0.4 — Unamortized deferred financing costs (10.7 ) (5.0 ) Unamortized debt discounts and premiums, net (5.5 ) (3.6 ) Total long-term debt at subsidiary 747.2 754.5 Bank term loan - rates from: 2.67% - 3.02% (a) and 2.44% - 2.67% (b) 2020 125.0 125.0 Senior unsecured bonds 6.5% — 130.0 Senior unsecured bonds 6.75% 2019 200.0 200.0 Senior unsecured bonds 7.25% 2021 780.0 780.0 Note to DPL Capital Trust II (c) 8.125% 2031 15.6 15.6 Unamortized deferred financing costs (8.8 ) (11.1 ) Unamortized debt discounts and premiums, net (0.6 ) (0.7 ) Subtotal 1,858.4 1,993.3 Less: current portion (29.7 ) (572.8 ) Total $ 1,828.7 $ 1,420.5 (a) Range of interest rates for the year ended December 31, 2016 . (b) Range of interest rates for the year ended December 31, 2015 . (c) Note payable to related party. See Note 13 – Related Party Transactions for additional information. |
Long-term Debt Maturities | At December 31, 2016 , maturities of long-term debt are summarized as follows: Due during the years ending December 31, $ in millions 2017 $ 29.7 2018 29.6 2019 229.6 2020 254.6 2021 784.6 Thereafter 555.5 1,883.6 Unamortized discounts and premiums, net (6.1 ) Total long-term debt $ 1,877.5 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Debt Instrument [Line Items] | |
Long-term Debt | Long-term debt is as follows: Long-term debt $ in millions Interest Rate Maturity December 31, 2016 December 31, 2015 Term loan - rates from: 4.00% - 4.01% (a) 2022 $ 445.0 $ — First Mortgage Bonds 1.875% — 445.0 Tax-exempt First Mortgage Bonds 4.8% 2036 100.0 100.0 Tax-exempt First Mortgage Bonds - rates from: 1.29% - 1.42% (a) and 1.13% - 1.17% (b) 2020 200.0 200.0 U.S. Government note 4.2% 2061 18.0 18.1 Capital leases 0.4 — Unamortized deferred financing costs (11.8 ) (6.2 ) Unamortized debt discount (2.2 ) (0.2 ) Subtotal 749.4 756.7 Less: current portion (4.7 ) (443.1 ) Total $ 744.7 $ 313.6 (a) Range of interest rates for the year ended December 31, 2016 . (b) Range of interest rates for the year ended December 31, 2015 |
Long-term Debt Maturities | At December 31, 2016 , maturities of long-term debt are summarized as follows: Due during the years ending December 31, $ in millions 2017 $ 4.7 2018 4.6 2019 4.6 2020 204.6 2021 4.5 Thereafter 540.0 763.0 Unamortized discounts and premiums, net (2.2 ) Total long-term debt $ 760.8 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Income Taxes [Line Items] | |
Components of Income Tax Expense | DPL’s components of income tax expense on continuing operations were as follows: Years ended December 31, $ in millions 2016 2015 2014 Computation of tax expense / (benefit) Federal income tax expense / (benefit) (a) $ (277.6 ) $ (81.0 ) $ 25.4 Increases (decreases) in tax resulting from: State income taxes, net of federal effect (1.0 ) (0.1 ) 0.8 Depreciation of AFUDC - Equity 2.7 (3.5 ) (3.4 ) Investment tax credit amortized (0.4 ) (0.5 ) (0.5 ) Section 199 - domestic production deduction (4.5 ) (4.1 ) (1.1 ) Non-deductible goodwill impairment — 111.0 — Accrual (settlement) for open tax years 2.2 — (6.6 ) Other, net (b) (0.2 ) (1.8 ) 0.8 Tax expense / (benefit) $ (278.8 ) $ 20.0 $ 15.4 Components of tax expense / (benefit) Federal - current $ 14.7 $ 30.1 $ (5.2 ) State and Local - current 0.6 0.8 0.4 Total current 15.3 30.9 (4.8 ) Federal - deferred (290.2 ) (9.9 ) 19.6 State and local - deferred (3.9 ) (1.0 ) 0.6 Total deferred (294.1 ) (10.9 ) 20.2 Tax expense / (benefit) $ (278.8 ) $ 20.0 $ 15.4 (a) The statutory tax rate of 35% was applied to pre-tax earnings. (b) Includes expense of $(0.3) million , $0.2 million and $0.4 million in the years ended December 31, 2016 , 2015 , and 2014 , respectively, of income tax related to adjustments from prior years. |
Schedule of Effective Income Tax Rate Reconciliation | The following table summarizes a reconciliation of the U.S. statutory federal income tax rate to DPL's effective tax rate, as a percentage of income from continuing operations before taxes for the years ended December 31, 2016 , 2015 and 2014 : Years ended December 31, 2016 2015 2014 Statutory Federal tax rate 35.0 % 35.0 % 35.0 % State taxes, net of Federal tax benefit 0.1 % 0.1 % 1.1 % AFUDC - Equity (0.3 )% 1.5 % (4.7 )% Amortization of investment tax credits — % 0.2 % (0.7 )% Section 199 - domestic production deduction 0.6 % 1.8 % (1.6 )% Non-deductible goodwill impairment — % (48.0 )% — % Other, net (0.3 )% 0.8 % (7.9 )% Effective tax rate 35.1 % (8.6 )% 21.2 % |
Components of Deferred Tax Assets and Liabilities | Components of Deferred Tax Assets and Liabilities December 31, $ in millions 2016 2015 Net non-current assets / (liabilities) Depreciation / property basis $ (255.3 ) $ (539.8 ) Income taxes recoverable (11.9 ) (12.0 ) Regulatory assets (7.8 ) (10.6 ) Investment tax credit 0.5 0.7 Compensation and employee benefits 5.5 3.1 Intangibles (1.5 ) (8.4 ) Long-term debt (0.7 ) (1.1 ) Other (a) 18.8 (0.6 ) Net non-current liabilities $ (252.4 ) $ (568.7 ) (a) The Other caption includes deferred tax assets of $24.9 million in 2016 and $26.0 million in 2015 related to state and local tax net operating loss carryforwards, net of related valuation allowances of $3.3 million in 2016 and $17.2 million in 2015 . These net operating loss carryforwards expire from 2017 to 2030. |
Schedule of Tax Expense Benefit That Were Credited To Accumulated Other Comprehensive Loss (Text Block) | The following table presents the tax expense / (benefit) related to pensions, postemployment benefits, cash flow hedges and financial instruments that were credited to Accumulated other comprehensive loss. Years ended December 31, $ in millions 2016 2015 2014 Tax expense / (benefit) $ (9.6 ) $ 6.3 $ (9.1 ) |
Reconciliation of Unrecognized Tax Benefits | A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows: $ in millions Balance at December 31, 2014 $ 3.0 Calendar 2015 Tax positions taken during prior period — Lapse of Statute of Limitations — Balance at December 31, 2015 3.0 Calendar 2016 Tax positions taken during prior period 2.2 Lapse of Statute of Limitations (1.5 ) Balance at December 31, 2016 $ 3.7 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Income Taxes [Line Items] | |
Components of Income Tax Expense | DP&L’s components of income tax expense were as follows: Years ended December 31, $ in millions 2016 2015 2014 Computation of tax expense / (benefit) Federal income tax expense / (benefit) (a) $ (418.5 ) $ 49.3 $ 53.8 Increases (decreases) in tax resulting from: State income taxes, net of federal effect (5.0 ) 0.4 1.2 Depreciation of AFUDC - Equity 3.3 (2.8 ) (2.7 ) Investment tax credit amortized (2.3 ) (2.4 ) (2.5 ) Section 199 - domestic production deduction (5.3 ) (6.1 ) (4.6 ) Accrual (settlement) for open tax years 3.4 — (6.6 ) Other, net (b) 2.0 (3.3 ) 1.1 Tax expense / (benefit) $ (422.4 ) $ 35.1 $ 39.7 Components of tax expense / (benefit) Federal - current $ 51.6 $ 55.8 $ 34.1 State and Local - current 0.6 0.8 0.5 Total current 52.2 56.6 34.6 Federal - deferred (466.3 ) (21.0 ) 4.1 State and local - deferred (8.3 ) (0.5 ) 1.0 Total deferred (474.6 ) (21.5 ) 5.1 Tax expense / (benefit) $ (422.4 ) $ 35.1 $ 39.7 (a) The statutory tax rate of 35% was applied to pre-tax earnings. (b) Includes expense of $2.9 million , expense of $0.4 million and benefit of $0.7 million in the years ended December 31, 2016 , 2015 and 2014 , respectively, of income tax related to adjustments from prior years. |
Schedule of Effective Income Tax Rate Reconciliation | The following table summarizes a reconciliation of the U.S. statutory federal income tax rate to DP&L's effective tax rate, as a percentage of income from continuing operations before taxes for the years ended December 31, 2016 , 2015 and 2014 : Years ended December 31, 2016 2015 2014 Statutory Federal tax rate 35.0 % 35.0 % 35.0 % State taxes, net of Federal tax benefit 0.4 % 0.3 % 0.8 % AFUDC - Equity (0.3 )% (2.0 )% (1.7 )% Amortization of investment tax credits 0.2 % (1.7 )% (1.6 )% Section 199 - domestic production deduction 0.4 % (4.3 )% (3.0 )% Other - net (0.4 )% (2.5 )% (3.8 )% Effective tax rate 35.3 % 24.8 % 25.7 % |
Components of Deferred Tax Assets and Liabilities | Components of Deferred Tax Assets and Liabilities December 31, $ in millions 2016 2015 Net non-current Assets / (Liabilities) Depreciation / property basis $ (129.8 ) $ (608.8 ) Income taxes recoverable (11.9 ) (12.0 ) Regulatory assets (9.1 ) (11.5 ) Investment tax credit 6.3 7.0 Compensation and employee benefits 1.1 3.6 Other (2.9 ) (9.5 ) Net non-current liabilities $ (146.3 ) $ (631.2 ) |
Schedule of Tax Expense Benefit That Were Credited To Accumulated Other Comprehensive Loss (Text Block) | The following table presents the tax (benefit) / expense related to pensions, postemployment benefits, cash flow hedges and financial instruments that were credited to Accumulated other comprehensive loss. Years ended December 31, $ in millions 2016 2015 2014 Tax expense / (benefit) $ (7.0 ) $ 7.5 $ (6.0 ) |
Reconciliation of Unrecognized Tax Benefits | A reconciliation of the beginning and ending amount of unrecognized tax benefits for DP&L is as follows: $ in millions Balance at December 31, 2014 $ 3.0 Calendar 2015 Tax positions taken during prior period — Lapse of Statute of Limitations — Balance at December 31, 2015 3.0 Calendar 2016 Tax positions taken during prior period 3.4 Lapse of Statute of Limitations (1.5 ) Balance at December 31, 2016 $ 4.9 |
Benefit Plans (Tables)
Benefit Plans (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Pension And Postretirement Benefit Plans' Obligations And Assets | The following tables set forth the changes in our pension plan's obligations and assets recorded on the balance sheets at December 31, 2016 and 2015 . The amounts presented in the following tables for pension obligations include the collective bargaining plan formula, traditional management plan formula and cash balance plan formula and the SERP in the aggregate and have not been adjusted for $1.3 million and $2.2 million of costs billed to the service company for the years ended December 31, 2016 and 2015 . $ in millions Pension Years ended December 31, 2016 2015 Change in benefit obligation Benefit obligation at January 1 $ 410.8 $ 443.8 Service cost 5.7 7.1 Interest cost 14.7 17.3 Plan curtailment 2.5 — Actuarial (gain) / loss 9.0 (34.5 ) Benefits paid (23.1 ) (22.9 ) Benefit obligation at December 31 419.6 410.8 Change in plan assets Fair value of plan assets at January 1 345.4 371.7 Actual return on plan assets 13.3 (8.8 ) Employer contributions 5.4 5.4 Benefits paid (23.1 ) (22.9 ) Fair value of plan assets at December 31 341.0 345.4 Unfunded status of plan $ (78.6 ) $ (65.4 ) December 31, Amounts recognized in the Balance sheets 2016 2015 Current liabilities $ (0.4 ) $ (0.4 ) Non-current liabilities (78.2 ) (65.0 ) Net liability at December 31, $ (78.6 ) $ (65.4 ) Amounts recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax Components: Prior service cost $ 8.8 $ 12.0 Net actuarial loss 108.9 94.7 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 117.7 $ 106.7 Recorded as: Regulatory asset $ 97.1 $ 91.1 Accumulated other comprehensive income 20.6 15.6 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 117.7 $ 106.7 |
Schedule of Amounts Recognized in Balance Sheet | The following tables set forth the changes in our pension plan's obligations and assets recorded on the balance sheets at December 31, 2016 and 2015 . The amounts presented in the following tables for pension obligations include the collective bargaining plan formula, traditional management plan formula and cash balance plan formula and the SERP in the aggregate and have not been adjusted for $1.3 million and $2.2 million of costs billed to the service company for the years ended December 31, 2016 and 2015 . $ in millions Pension Years ended December 31, 2016 2015 Change in benefit obligation Benefit obligation at January 1 $ 410.8 $ 443.8 Service cost 5.7 7.1 Interest cost 14.7 17.3 Plan curtailment 2.5 — Actuarial (gain) / loss 9.0 (34.5 ) Benefits paid (23.1 ) (22.9 ) Benefit obligation at December 31 419.6 410.8 Change in plan assets Fair value of plan assets at January 1 345.4 371.7 Actual return on plan assets 13.3 (8.8 ) Employer contributions 5.4 5.4 Benefits paid (23.1 ) (22.9 ) Fair value of plan assets at December 31 341.0 345.4 Unfunded status of plan $ (78.6 ) $ (65.4 ) December 31, Amounts recognized in the Balance sheets 2016 2015 Current liabilities $ (0.4 ) $ (0.4 ) Non-current liabilities (78.2 ) (65.0 ) Net liability at December 31, $ (78.6 ) $ (65.4 ) Amounts recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax Components: Prior service cost $ 8.8 $ 12.0 Net actuarial loss 108.9 94.7 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 117.7 $ 106.7 Recorded as: Regulatory asset $ 97.1 $ 91.1 Accumulated other comprehensive income 20.6 15.6 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 117.7 $ 106.7 |
Schedule of Net Periodic Benefit Cost / (Income) | Net Periodic Benefit Cost Years ended December 31, $ in millions 2016 2015 2014 Service cost $ 5.7 $ 7.1 $ 5.9 Interest cost 14.7 17.3 17.5 Expected return on assets (22.8 ) (22.6 ) (22.9 ) Plan curtailment 3.8 — — Amortization of unrecognized: Actuarial loss 4.3 5.8 3.4 Prior service cost 1.8 2.0 1.5 Net periodic benefit cost $ 7.5 $ 9.6 $ 5.4 Rates relevant to each year's expense calculations Discount rate 4.49 % 4.02 % 4.86 % Expected return on plan assets 6.50 % 6.50 % 6.75 % Other Changes in Plan Assets and Benefit Obligation Recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities |
Other Changes in Plan Assets and Benefit Obligation Recognized in Accumulated Other Comprehensive Income, Regulatory Assets And Regulatory Liabilities | Other Changes in Plan Assets and Benefit Obligation Recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities Years ended December 31, $ in millions 2016 2015 2014 Net actuarial loss / (gain) $ 20.9 $ (3.0 ) $ 43.8 Prior service cost — — 6.8 Plan curtailment (3.8 ) — — Reversal of amortization item: Net actuarial loss (4.3 ) (5.8 ) (3.4 ) Prior service cost (1.8 ) (2.0 ) (1.5 ) Total recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities $ 11.0 $ (10.8 ) $ 45.7 Total recognized in net periodic benefit cost and Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities $ 18.5 $ (1.2 ) $ 51.1 |
Estimated Amounts that will be Amortized from Accumulated Other Comprehensive Income, Regulatory Assets And Regulatory Liabilities | Estimated amounts that will be amortized from AOCI, Regulatory assets and Regulatory liabilities into net periodic benefit costs during 2017 are: $ in millions Pension Actuarial loss $ 5.8 Prior service cost $ 1.4 |
Weighted Average Assumptions Used to Determine Benefit Obligations | The weighted average assumptions used to determine benefit obligations at December 31, 2016 , 2015 and 2014 were: Benefit Obligation Assumptions Pension 2016 2015 2014 Discount rate for obligations 4.28% 4.49% 4.02% Rate of compensation increases 3.94% 3.94% 3.94% |
Schedule of Allocation of Plan Assets | The following table summarizes our target pension plan allocation for 2016 : Long-Term Target Allocation Percentage of plan assets as of December 31, Asset category 2016 2015 Equity Securities 38% 37% 17% Debt Securities 56% 53% 67% Real Estate 6% 10% 9% Other —% —% 7% |
Estimated Future Benefit Payments and Medicare Part D Reimbursements | Estimated future benefit payments $ in millions due within the following years: Pension 2017 $ 25.0 2018 $ 25.5 2019 $ 26.0 2020 $ 26.4 2021 $ 26.7 2022 - 2026 $ 139.6 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Schedule of Amounts Recognized in Balance Sheet | December 31, 2016 and 2015 . The amounts presented in the following tables for pension obligations include the collective bargaining plan formula, traditional management plan formula and cash balance plan formula and the SERP in the aggregate and have not been adjusted for $1.3 million and $2.2 million of costs billed to the service company for the years ended December 31, 2016 and 2015 . $ in millions Pension Years ended December 31, 2016 2015 Change in benefit obligation Benefit obligation at January 1 $ 410.8 $ 443.8 Service cost 5.7 7.1 Interest cost 14.7 17.3 Plan curtailment 2.5 — Actuarial (gain) / loss 9.0 (34.5 ) Benefits paid (23.1 ) (22.9 ) Benefit obligation at December 31 419.6 410.8 Change in plan assets Fair value of plan assets at January 1 345.4 371.7 Actual return on plan assets 13.3 (8.8 ) Employer contributions 5.4 5.4 Benefits paid (23.1 ) (22.9 ) Fair value of plan assets at December 31 341.0 345.4 Funded status of plan $ (78.6 ) $ (65.4 ) December 31, Amounts recognized in the Balance sheets 2016 2015 Current liabilities $ (0.4 ) $ (0.4 ) Non-current liabilities (78.2 ) (65.0 ) Net liability $ (78.6 ) $ (65.4 ) Amounts recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax Components: Prior service cost $ 10.8 $ 17.0 Net actuarial loss 150.9 139.7 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 161.7 $ 156.7 Recorded as: Regulatory asset $ 97.1 $ 91.1 Accumulated other comprehensive income 64.6 65.6 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 161.7 $ 156.7 |
Schedule of Net Periodic Benefit Cost / (Income) | Net Periodic Benefit Cost Years ended December 31, $ in millions 2016 2015 2014 Service cost $ 5.7 $ 7.1 $ 5.9 Interest cost 14.7 17.3 17.5 Expected return on assets (22.8 ) (22.6 ) (22.9 ) Plan curtailment 5.7 — — Amortization of unrecognized: Actuarial loss 7.2 9.8 6.4 Prior service cost 3.0 3.3 2.8 Net periodic benefit cost $ 13.5 $ 14.9 $ 9.7 Rates relevant to each year's expense calculations Discount rate 4.49 % 4.02 % 4.86 % Expected return on plan assets 6.50 % 6.50 % 6.75 % |
Estimated Amounts that will be Amortized from Accumulated Other Comprehensive Income, Regulatory Assets And Regulatory Liabilities | Estimated amounts that will be amortized from AOCI, Regulatory assets and Regulatory liabilities into net periodic benefit costs during 2017 are: $ in millions Pension Actuarial loss $ 9.7 Prior service cost $ 1.9 |
Weighted Average Assumptions Used to Determine Benefit Obligations | The weighted average assumptions used to determine benefit obligations at December 31, 2016 , 2015 and 2014 were: Benefit Obligation Assumptions Pension 2016 2015 2014 Discount rate for obligations 4.28% 4.49% 4.02% Rate of compensation increases 3.94% 3.94% 3.94% |
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost (Income) | |
Assumed Health Care Cost Trend Rates | |
Effect of Change in Health Care Cost Trend Rate | |
Schedule of Allocation of Plan Assets | The following table summarizes our target pension plan allocation for 2016 : Long-Term Target Allocation Percentage of plan assets as of December 31, Asset Category 2016 2015 Equity Securities 38% 37% 17% Debt Securities 56% 53% 67% Real Estate 6% 10% 9% Other —% —% 7% |
Fair Value Measurements for Plan Assets | The fair values of our pension plan assets at December 31, 2016 by asset category are as follows: Fair Value Measurements for Pension Plan Assets at December 31, 2016 Asset Category $ in millions Market Value at December 31, 2016 Quoted prices in active markets for identical assets Significant observable inputs Significant unobservable inputs (Level 1) (Level 2) (Level 3) Mutual funds: U.S. equities (a) $ 81.4 $ 81.4 $ — $ — International equities (a) 44.4 44.4 — — Fixed income (b) 151.1 151.1 — — Fixed income securities U.S. Treasury securities 31.0 31.0 — — Other investments: Core property collective fund (c) 33.1 — 33.1 — Total pension plan assets $ 341.0 $ 307.9 $ 33.1 $ — (a) This category includes investments in equity securities of large, small and medium sized U.S. companies and equity securities of foreign companies including those in developing countries. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund. (b) This category includes investments in investment-grade fixed-income instruments, U.S. dollar-denominated debt securities of emerging market issuers and high yield fixed-income securities that are rated below investment grade. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund. (c) This category represents a property fund that invests in commercial real estate. The fair value of the fund is valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund. The fair values of our pension plan assets at December 31, 2015 by asset category are as follows: Fair Value Measurements for Pension Plan Assets at December 31, 2015 Asset Category $ in millions Market Value at December 31, 2015 Quoted prices in active markets for identical assets Significant observable inputs Significant unobservable inputs (Level 1) (Level 2) (Level 3) Mutual funds: U.S. equities (a) $ 39.4 $ 39.4 $ — $ — International equities (a) 20.9 20.9 — — Fixed income (b) 232.1 232.1 — — Other investments: (c) Core property collective fund 30.2 — 30.2 — Common collective fund 22.8 — 22.8 — Total pension plan assets $ 345.4 $ 292.4 $ 53.0 $ — (a) This category includes investments in equity securities of large, small and medium sized U.S. companies and equity securities of foreign companies including those in developing countries. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund. (b) This category includes investments in investment-grade fixed-income instruments, U.S. dollar-denominated debt securities of emerging market issuers and high yield fixed-income securities that are rated below investment grade. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund. (c) This category represents a property fund that invests in commercial real estate and a hedge fund of funds made up of 30+ different hedge fund managers diversified over eight different hedge strategies. The fair value of the hedge fund is valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund. |
Estimated Future Benefit Payments and Medicare Part D Reimbursements | Estimated future benefit payments $ in millions due within the following years: Pension 2017 $ 25.0 2018 $ 25.5 2019 $ 26.0 2020 $ 26.4 2021 $ 26.7 2022 - 2026 $ 139.6 |
Pension [Member] | |
Fair Value Measurements for Plan Assets | The fair values of our pension plan assets at December 31, 2016 by asset category are as follows: Fair Value Measurements for Pension Plan Assets at December 31, 2016 Asset Category $ in millions Market Value at December 31, 2016 Quoted prices in active markets for identical assets Significant observable inputs Significant unobservable inputs (Level 1) (Level 2) (Level 3) Mutual funds: U.S. equities (a) $ 81.4 $ 81.4 $ — $ — International equities (a) 44.4 44.4 — — Fixed income (b) 151.1 151.1 — — Fixed income securities: U.S. Treasury securities 31.0 31.0 — — Other investments: Core property collective fund (c) 33.1 — 33.1 — Total pension plan assets $ 341.0 $ 307.9 $ 33.1 $ — (a) This category includes investments in equity securities of large, small and medium sized U.S. companies and equity securities of foreign companies including those in developing countries. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund. (b) This category includes investments in investment-grade fixed-income instruments, U.S. dollar-denominated debt securities of emerging market issuers and high yield fixed-income securities that are rated below investment grade. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund. (c) This category represents a property fund that invests in commercial real estate. The fair value of the fund is valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund. The fair values of our pension plan assets at December 31, 2015 by asset category are as follows: Fair Value Measurements for Pension Plan Assets at December 31, 2015 Asset Category $ in millions Market Value at December 31, 2015 Quoted prices in active markets for identical assets Significant observable inputs Significant unobservable inputs (Level 1) (Level 2) (Level 3) Mutual funds: U.S. equities (a) $ 39.4 $ 39.4 $ — $ — International equities (a) 20.9 20.9 — — Fixed income (b) 232.1 232.1 — — Other investments: (c) Core property collective fund 30.2 — 30.2 — Common collective fund 22.8 — 22.8 — Total pension plan assets $ 345.4 $ 292.4 $ 53.0 $ — (a) This category includes investments in equity securities of large, small and medium sized U.S. companies and equity securities of foreign companies including those in developing countries. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund. (b) This category includes investments in investment-grade fixed-income instruments, U.S. dollar-denominated debt securities of emerging market issuers and high yield fixed-income securities that are rated below investment grade. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund. (c) This category represents a property fund that invests in commercial real estate and a hedge fund of funds made up of 30+ different hedge fund managers diversified over eight different hedge strategies. The fair value of the hedge fund is valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund. |
Pension [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Pension And Postretirement Benefit Plans' Obligations And Assets | $ in millions Pension Years ended December 31, 2016 2015 Change in benefit obligation Benefit obligation at January 1 $ 410.8 $ 443.8 Service cost 5.7 7.1 Interest cost 14.7 17.3 Plan curtailment 2.5 — Actuarial (gain) / loss 9.0 (34.5 ) Benefits paid (23.1 ) (22.9 ) Benefit obligation at December 31 419.6 410.8 Change in plan assets Fair value of plan assets at January 1 345.4 371.7 Actual return on plan assets 13.3 (8.8 ) Employer contributions 5.4 5.4 Benefits paid (23.1 ) (22.9 ) Fair value of plan assets at December 31 341.0 345.4 Funded status of plan $ (78.6 ) $ (65.4 ) December 31, Amounts recognized in the Balance sheets 2016 2015 Current liabilities $ (0.4 ) $ (0.4 ) Non-current liabilities (78.2 ) (65.0 ) Net liability $ (78.6 ) $ (65.4 ) Amounts recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax Components: Prior service cost $ 10.8 $ 17.0 Net actuarial loss 150.9 139.7 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 161.7 $ 156.7 Recorded as: Regulatory asset $ 97.1 $ 91.1 Accumulated other comprehensive income 64.6 65.6 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 161.7 $ 156.7 |
Other Changes in Plan Assets and Benefit Obligation Recognized in Accumulated Other Comprehensive Income, Regulatory Assets And Regulatory Liabilities | Other Changes in Plan Assets and Benefit Obligation Recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities Years ended December 31, $ in millions 2016 2015 2014 Net actuarial loss / (gain) $ 20.9 $ (3.0 ) $ 43.8 Prior service cost — — 6.8 Plan curtailment (5.7 ) — — Reversal of amortization item: Net actuarial loss (7.2 ) (9.8 ) (6.4 ) Prior service cost (3.0 ) (3.3 ) (2.8 ) Total recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities $ 5.0 $ (16.1 ) $ 41.4 Total recognized in net periodic benefit cost and Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities $ 18.5 $ (1.2 ) $ 51.1 |
Postretirement [Member] | |
Fair Value Measurements for Plan Assets | Pension funding |
Postretirement [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Pension And Postretirement Benefit Plans' Obligations And Assets | |
Fair Value Measurements for Plan Assets |
Equity (Tables)
Equity (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Entity Information [Line Items] | |
Preferred Shares Outstanding | The table below details the preferred shares outstanding at December 31, 2016 and 2015 : Carrying Value (b) ($ in millions) Preferred Stock Rate Redemption price ($ per share) Shares Outstanding (a) December 31, 2016 December 31, 2015 DP&L Series A 3.75% $ 102.50 93,280 $ — $ 7.4 DP&L Series B 3.75% $ 103.00 69,398 — 5.6 DP&L Series C 3.90% $ 101.00 65,830 — 5.4 Total 228,508 $ — $ 18.4 (a) DP&L's preferred stock was redeemed in October 2016. See below for more information. (b) Carrying value is fair value at the Merger date plus cumulative accrued dividends, of which there were none at December 31, 2016 and 2015 . |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Entity Information [Line Items] | |
Preferred Shares Outstanding | The table below details the preferred shares outstanding at December 31, 2016 and 2015 : Par Value ($ in millions) Preferred Stock Rate Redemption price ($ per share) Shares Outstanding (a) December 31, 2016 December 31, 2015 DP&L Series A 3.75% $ 102.50 93,280 $ — $ 9.3 DP&L Series B 3.75% $ 103.00 69,398 — 7.0 DP&L Series C 3.90% $ 101.00 65,830 — 6.6 Total 228,508 $ — $ 22.9 |
Contractual Obligations, Comm40
Contractual Obligations, Commercial Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Schedule Of Contractual Obligations And Commercial Commitments | We enter into various contractual obligations and other commercial commitments that may affect the liquidity of our operations. At December 31, 2016 , these include: Payments due in: $ in millions Total Less than 1 year 2 - 3 years 4 - 5 years More than 5 years DPL: Coal and limestone contracts (a) $ 284.3 $ 230.3 $ 54.0 $ — $ — Purchase orders and other contractual obligations $ 109.8 $ 43.1 $ 33.6 $ 33.1 $ — (a) Total at DP&L operated units. |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Schedule Of Contractual Obligations And Commercial Commitments | We enter into various contractual obligations and other commercial commitments that may affect the liquidity of our operations. At December 31, 2016 , these include: Payments due in: $ in millions Total Less than 1 year 2 - 3 years 4 - 5 years More than 5 years DP&L: Coal and limestone contracts (a) $ 284.3 $ 230.3 $ 54.0 $ — $ — Purchase orders and other contractual obligations $ 109.8 $ 43.1 $ 33.6 $ 33.1 $ — (a) Total at DP&L operated units. |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Entity Information [Line Items] | |
Schedule of Related Party Transactions | The following table provides a summary of these transactions: For the years ended December 31, $ in millions 2016 2015 2014 Transactions with the Service Company Charges for services provided $ 42.8 $ 36.0 $ 35.8 Charges to the Service Company $ 4.6 $ 6.2 $ 2.4 Transactions with other AES affiliates: Payments for health, welfare and benefit plans $ 9.6 $ 15.5 $ 17.8 Balances with related parties: At December 31, 2016 At December 31, 2015 Net payable to the Service Company $ (2.0 ) $ (0.5 ) Net prepayment with / (payable) to other AES affiliates $ (2.5 ) $ 0.1 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Entity Information [Line Items] | |
Schedule of Related Party Transactions | The following table provides a summary of these transactions: Years ended December 31, $ in millions 2016 2015 2014 DP&L revenues: Sales to DPLER (including MC Squared) (a) $ — $ 303.3 $ 487.1 DP&L Operation & Maintenance Expenses: Premiums paid for insurance services provided by MVIC (b) $ (3.4 ) $ (3.2 ) $ (2.9 ) Expense recoveries for services provided to DPLER (c) $ — $ 2.4 $ 2.2 Transactions with the Service Company: Charges for services provided $ 38.7 $ 30.9 $ 30.5 Charges to the Service Company $ 4.5 $ 6.1 $ 2.3 Transactions with other AES affiliates: Payments for health, welfare and benefit plans $ 9.4 $ 14.8 $ 17.1 Balances with related parties: At December 31, 2016 At December 31, 2015 Net payable to the Service Company $ (2.0 ) $ (0.5 ) Short-term loan with DPL $ 5.0 $ 35.0 Net prepayment with / (payable) to other AES affiliates $ (2.5 ) $ 0.1 (a) DP&L sold power to DPLER and MC Squared to satisfy the electric requirements of their retail customers. The revenue dollars associated with sales to DPLER and MC Squared are recorded as wholesale revenues in DP&L’s Financial Statements. These agreements were terminated on the sale of DPLER on January 1, 2016. (b) MVIC, a wholly-owned captive insurance subsidiary of DPL , provides insurance coverage to DP&L and other DPL subsidiaries for workers’ compensation, general liability, property damages and directors’ and officers’ liability. These amounts represent insurance premiums paid by DP&L to MVIC. (c) In the normal course of business DP&L incurred and recorded expenses on behalf of DPLER. Such expenses included but were not limited to employee-related expenses, accounting, information technology, payroll, legal and other administration expenses. DP&L subsequently charged these expenses to DPLER at DP&L’s cost and credited the expense in which they were initially recorded. |
Business Segments Business Segm
Business Segments Business Segments (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Segment Reporting Information [Line Items] | |
Schedule of Segment Reporting Information, by Segment [Table Text Block] | The following tables present financial information for each of DPL’s reportable business segments: $ in millions T&D Generation Other Adjustments and Eliminations DPL Consolidated Year ended December 31, 2016 Revenues from external customers $ 806.7 $ 611.5 $ 9.1 $ — $ 1,427.3 Intersegment revenues 1.3 — 5.7 (7.0 ) — Total revenues $ 808.0 $ 611.5 $ 14.8 $ (7.0 ) $ 1,427.3 Depreciation and amortization $ 71.0 $ 55.4 $ 5.9 $ — $ 132.3 Fixed-asset impairment (Note 15) $ — $ 1,353.5 $ (494.5 ) $ — $ 859.0 Interest expense $ 24.7 $ 0.4 $ 81.3 $ (0.3 ) $ 106.1 Income / (loss) from continuing operations before income tax $ 143.0 $ (1,353.9 ) $ 417.6 $ — $ (793.3 ) Cash capital expenditures $ 83.4 $ 64.2 $ 0.9 $ — $ 148.5 Total assets (end of year) $ 1,710.5 $ 472.3 $ 673.6 $ (437.2 ) $ 2,419.2 $ in millions T&D Generation Other Adjustments and Eliminations DPL Consolidated Year ended December 31, 2015 Revenues from external customers (b) $ 855.5 $ 770.3 $ 6.7 $ (19.7 ) $ 1,612.8 Intersegment revenues 1.5 186.6 4.2 (192.3 ) — Total revenues $ 857.0 $ 956.9 $ 10.9 $ (212.0 ) $ 1,612.8 Depreciation and amortization $ 71.5 $ 72.6 $ (9.5 ) $ — $ 134.6 Goodwill impairment (Note 7) $ — $ — $ 317.0 $ — $ 317.0 Interest expense $ 28.9 $ 2.9 $ 86.8 $ (0.3 ) $ 118.3 Income / (loss) from continuing operations before income tax $ 188.1 $ (28.7 ) $ (390.8 ) $ — $ (231.4 ) Cash capital expenditures $ 98.3 $ 35.2 $ 3.7 $ — $ 137.2 Total assets (end of year) (a) $ 1,688.8 $ 1,805.0 $ 1,170.3 $ (1,339.4 ) $ 3,324.7 (a) Includes assets held for sale related to the sale of DPLER. (b) Wholesale revenue for the T&D segment in 2015 includes OVEC revenue of $19.7 million that was previously netted in purchased power. The impact of this netting adjustment is included in the Adjustments and Eliminations column in the table above but has no impact on consolidated revenues or Income / (loss) from continuing operations before income tax. $ in millions T&D Generation Other Adjustments and Eliminations DPL Consolidated Year ended December 31, 2014 Revenues from external customers (b) $ 1,020.1 $ 721.8 $ 7.1 $ (32.5 ) $ 1,716.5 Intersegment revenues 1.7 72.8 3.8 (78.3 ) — Total revenues $ 1,021.8 $ 794.6 $ 10.9 $ (110.8 ) $ 1,716.5 Depreciation and amortization $ 75.5 $ 75.3 $ (15.2 ) $ — $ 135.6 Fixed asset impairment (Note 15) $ — $ — $ 11.5 $ — $ 11.5 Interest expense $ 29.8 $ 5.0 $ 92.5 $ (0.7 ) $ 126.6 Income / (loss) from continuing operations before income tax $ 241.7 $ (78.0 ) $ (91.1 ) $ — $ 72.6 Cash capital expenditures $ 100.4 $ 14.5 $ 3.2 $ — $ 118.1 Total assets (end of year) (a) $ 1,686.1 $ 1,771.4 $ 1,397.5 $ (1,295.9 ) $ 3,559.1 (a) Includes assets held for sale related to the sale of DPLER. (b) Wholesale revenue for 2014 was not restated for the impact of netting between wholesale revenue and purchased power for the Generation segment because it was impracticable to restate. This impacts the Generation revenue as well as the revenue in the Adjustments and Eliminations column in the table above but has no impact on consolidated revenues or Income / (loss) from continuing operations before income tax. In addition, w holesale revenue for the T&D segment in 2014 includes OVEC revenue of $32.5 million that was previously netted in purchased power. The impact of this netting adjustment is included in the Adjustments and Eliminations column in the table above but has no impact on consolidated revenues or Income / (loss) from continuing operations before income tax. |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Segment Reporting Information [Line Items] | |
Schedule of Segment Reporting Information, by Segment [Table Text Block] | The following tables present financial information for each of DP&L’s reportable business segments: $ in millions T&D Generation Adjustments and Eliminations DP&L Total Year ended December 31, 2016 Revenues from external customers $ 808.0 $ 557.9 $ — $ 1,365.9 Intersegment revenues — — — — Total revenues $ 808.0 $ 557.9 $ — $ 1,365.9 Depreciation and amortization $ 71.0 $ 49.3 $ — $ 120.3 Fixed-asset impairment (Note 14) $ — $ 1,353.5 $ — $ 1,353.5 Interest expense $ 24.0 $ 0.5 $ — $ 24.5 Income / (loss) from operations before income tax $ 143.6 $ (1,338.7 ) $ — $ (1,195.1 ) Cash capital expenditures $ 83.4 $ 44.9 $ — $ 128.3 Total assets (end of year) $ 1,710.5 $ 324.6 $ — $ 2,035.1 $ in millions T&D Generation Adjustments and Eliminations DP&L Total Year ended December 31, 2015 Revenues from external customers (a) $ 857.0 $ 715.0 $ (19.7 ) $ 1,552.3 Intersegment revenues — 186.6 (186.6 ) — Total revenues $ 857.0 $ 901.6 $ (206.3 ) $ 1,552.3 Depreciation and amortization $ 71.5 $ 66.7 $ — $ 138.2 Interest expense $ 28.0 $ 2.9 $ — $ 30.9 Income / (loss) from operations before income tax $ 189.0 $ (47.5 ) $ — $ 141.5 Cash capital expenditures $ 98.3 $ 28.7 $ — $ 127.0 Total assets (end of year) $ 1,688.8 $ 1,670.8 $ — $ 3,359.6 (a) Wholesale revenue for the T&D segment in 2015 includes OVEC revenue of $19.7 million that was previously netted in purchased power. The impact of this netting adjustment is included in the Adjustments and Eliminations column in the table above but has no impact on consolidated revenues or Income / (loss) from continuing operations before income tax. $ in millions T&D Generation Adjustments and Eliminations DP&L Total Year ended December 31, 2014 Revenues from external customers (a) $ 1,021.8 $ 679.0 $ (32.5 ) $ 1,668.3 Intersegment revenues — 72.8 (72.8 ) — Total revenues $ 1,021.8 $ 751.8 $ (105.3 ) $ 1,668.3 Depreciation and amortization $ 75.5 $ 69.3 $ — $ 144.8 Interest expense $ 28.9 $ 5.0 $ — $ 33.9 Income / (loss) from operations before income tax $ 242.6 $ (87.9 ) $ — $ 154.7 Cash capital expenditures $ 100.4 $ 13.8 $ — $ 114.2 Total assets (end of year) $ 1,686.1 $ 1,642.7 $ — $ 3,328.8 (a) Wholesale revenue for 2014 was not restated for the impact of netting between wholesale revenue and purchased power for the Generation segment because it was impracticable to restate. This impacts the Generation revenue as well as the revenue in the Adjustments and Eliminations column in the table above but has no impact on consolidated revenues or Income / (loss) from continuing operations before income tax. In addition, w holesale revenue for the T&D segment in 2014 includes OVEC revenue of $32.5 million that was previously netted in purchased power. The impact of this netting adjustment is included in the Adjustments and Eliminations column in the table above but has no impact on consolidated revenues or Income / (loss) from continuing operations before income tax. |
Fixed Asset Impairment Fixed As
Fixed Asset Impairment Fixed Asset Impairment (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Property, Plant and Equipment [Line Items] | |
Schedule of Fixed Asset Impairments | During the years ended December 31, 2016, 2015 and 2014, DPL had the following fixed-asset impairments: Years ended December 31, Measurement Date 2016 2015 2014 Killen December 31, 2016 $ 75.4 $ — $ — Stuart December 31, 2016 228.5 — — Miami Fort December 31, 2016 149.4 — — Zimmer December 31, 2016 144.7 — — Conesville December 31, 2016 23.9 — — Hutchings peaking facilities December 31, 2016 1.6 — — Killen June 30, 2016 230.8 — — Certain peaking facilities June 30, 2016 4.7 — — East Bend March 31, 2014 — — 11.5 Total impairment loss $ 859.0 $ — $ 11.5 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Property, Plant and Equipment [Line Items] | |
Schedule of Fixed Asset Impairments | During the years ended December 31, 2016, 2015 and 2014, DP&L had the following fixed-asset impairments: Years ended December 31, Measurement Date 2016 2015 2014 Killen December 31, 2016 $ 75.3 $ — $ — Stuart December 31, 2016 149.9 — — Miami Fort December 31, 2016 157.7 — — Zimmer December 31, 2016 91.3 — — Conesville December 31, 2016 20.8 — — Hutchings peaking facilities December 31, 2016 1.4 — — Stuart June 30, 2016 292.0 — — Killen June 30, 2016 246.2 — — Zimmer June 30, 2016 318.9 — — Total impairment loss $ 1,353.5 $ — $ — |
Discontinued Operations (Tables
Discontinued Operations (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Summary of Balance Sheet and Profit and Loss Information for Discontinued Operations | The following table summarizes the major categories of assets, liabilities at the dates indicated, and the revenues, cost of revenues, operating expenses and income tax of discontinued operations for the periods indicated: $ in millions December 31, 2015 Accounts receivable, net $ 31.0 Property, plant & equipment, net 1.1 Intangible assets, net 28.1 Other assets 2.0 Total assets of the disposal group classified as held for sale in the balance sheets $ 62.2 Accounts payable $ 0.8 Other liabilities 0.8 Total liabilities of the disposal group classified as held for sale in the balance sheets $ 1.6 Years ended December 31, 2016 2015 2014 Revenues $ — $ 340.9 $ 533.6 Cost of revenues — (307.0 ) (493.0 ) Operating expenses (0.7 ) (22.5 ) (34.0 ) Goodwill impairment — — (135.8 ) Profit / (loss) of discontinued operations before income taxes (0.7 ) 11.4 (129.2 ) Gain from disposal of discontinued operations 49.2 — — Income tax expense / (benefit) 19.2 (1.0 ) 2.6 Income / (loss) on discontinued operations $ 29.3 $ 12.4 $ (131.8 ) |
Overview and Summary of Signi45
Overview and Summary of Significant Accounting Policies (Narrative) (Details) | Jan. 31, 2017employee | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($)mi²customergenerating_facilitysegment | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) |
Significant Accounting Policies [Line Items] | |||||
Capitalized Software, estimated amortization expense for year after next | $ 5,600,000 | ||||
Capitalized Computer Software, Gross | $ 65,100,000 | $ 59,900,000 | |||
Number of reportable segments | segment | 2 | ||||
Service area, square miles | mi² | 6,000 | ||||
Number of coal fired power plants | generating_facility | 5 | ||||
Capitalized interest for unregulated generation propety | $ 2,800,000 | $ 2,000,000 | $ 1,500,000 | ||
Straight-line depreciation average annual composite basis (percent) | 6.10% | 4.40% | 5.30% | ||
Depreciation and amortization | $ 132,300,000 | $ 134,600,000 | $ 135,600,000 | ||
Insurance and claims costs | 5,400,000 | 5,900,000 | |||
Insurance costs below coverage thresholds of third-party providers | 12,000,000 | 13,700,000 | |||
Investment in trust | 300,000 | 300,000 | |||
Capitalized Computer Software, Accumulated Amortization | $ 43,200,000 | 35,300,000 | |||
Finite-Lived Intangible Asset, Useful Life | 7 years | ||||
Capitalized Computer Software, Amortization | $ 7,700,000 | 9,000,000 | 8,600,000 | ||
Capitalized Software, estimated amortization over remaining useful life | 15,300,000 | ||||
Capitalized Software, estimated amortization expense for next twelve months | 6,100,000 | ||||
Capitalized Software, estimated amortization expense for three years in the future | 4,000,000 | ||||
Capitalized Software, estimated amortization expense for four years in the future | 0 | ||||
Capitalized Software, estimated amortization expense for five years in the future | 0 | ||||
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Capitalized Software, estimated amortization expense for year after next | 5,600,000 | ||||
Capitalized Computer Software, Gross | $ 78,500,000 | 73,900,000 | |||
Number of reportable segments | segment | 2 | ||||
Approximate number of retail customers | customer | 519,000 | ||||
Service area, square miles | mi² | 6,000 | ||||
Number of coal fired power plants | generating_facility | 5 | ||||
Capitalized interest for unregulated generation propety | $ 2,700,000 | $ 2,000,000 | $ 1,500,000 | ||
Straight-line depreciation average annual composite basis (percent) | 4.60% | 2.50% | 2.80% | ||
Depreciation and amortization | $ 120,300,000 | $ 138,200,000 | $ 144,800,000 | ||
Insurance costs below coverage thresholds of third-party providers | 11,800,000 | 13,700,000 | |||
Capitalized Computer Software, Accumulated Amortization | $ 56,400,000 | 49,200,000 | |||
Finite-Lived Intangible Asset, Useful Life | 7 years | ||||
Capitalized Computer Software, Amortization | $ 7,500,000 | 8,200,000 | 8,000,000 | ||
Capitalized Software, estimated amortization over remaining useful life | 15,300,000 | ||||
Capitalized Software, estimated amortization expense for next twelve months | 6,100,000 | ||||
Capitalized Software, estimated amortization expense for three years in the future | 4,000,000 | ||||
Capitalized Software, estimated amortization expense for four years in the future | 0 | ||||
Capitalized Software, estimated amortization expense for five years in the future | 0 | ||||
Note to DPL Capital Trust II Maturing in 2031 - 8.125% [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Note payable to trust | 15,600,000 | 15,600,000 | |||
Subsequent Event [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Entity number of employees | employee | 1,168 | ||||
Employees under collective bargaining agreement (percent) | 62.00% | ||||
Subsequent Event [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Entity number of employees | employee | 1,160 | ||||
Percentage Of Employees Under Collective Bargaining Agreement | 63.00% | ||||
Electric Generation, Transmission and Distribution Equipment [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Depreciation and amortization | 121,900,000 | 125,900,000 | 128,100,000 | ||
Electric Generation, Transmission and Distribution Equipment [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Depreciation and amortization | 110,000,000 | 132,700,000 | 141,600,000 | ||
Pension [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Service cost | 5,700,000 | 7,100,000 | 5,900,000 | ||
Interest cost | 14,700,000 | 17,300,000 | 17,500,000 | ||
Pension [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Service cost | 5,700,000 | 7,100,000 | 5,900,000 | ||
Interest cost | 14,700,000 | 17,300,000 | $ 17,500,000 | ||
Pension [Member] | Scenario, Forecast [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Service cost | $ 5,700,000 | ||||
Pension [Member] | Scenario, Forecast [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Service cost | $ 5,700,000 | ||||
Disaggregated Rate Approach [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Service cost | 5,900,000 | ||||
Interest cost | 15,300,000 | ||||
Disaggregated Rate Approach [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Service cost | 5,900,000 | ||||
Interest cost | 15,300,000 | ||||
Disaggregated Rate Approach [Member] | Pension [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Service cost | 5,700,000 | ||||
Interest cost | 14,700,000 | ||||
Disaggregated Rate Approach [Member] | Pension [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Service cost | 5,700,000 | ||||
Interest cost | 14,700,000 | ||||
Disaggregated Rate Approach [Member] | Postretirement [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Service cost | 200,000 | ||||
Interest cost | 600,000 | ||||
Disaggregated Rate Approach [Member] | Postretirement [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Service cost | 200,000 | ||||
Interest cost | 600,000 | ||||
Aggregate Rate Approach [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Service cost | 6,300,000 | ||||
Interest cost | 18,600,000 | ||||
Aggregate Rate Approach [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Service cost | 6,300,000 | ||||
Interest cost | 18,600,000 | ||||
Aggregate Rate Approach [Member] | Pension [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Service cost | 6,100,000 | ||||
Interest cost | 17,900,000 | ||||
Aggregate Rate Approach [Member] | Pension [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Service cost | 6,100,000 | ||||
Interest cost | 17,900,000 | ||||
Aggregate Rate Approach [Member] | Postretirement [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Service cost | 200,000 | ||||
Interest cost | 700,000 | ||||
Aggregate Rate Approach [Member] | Postretirement [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Service cost | 200,000 | ||||
Interest cost | 700,000 | ||||
Impact of Change [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Service cost | (400,000) | ||||
Interest cost | (3,300,000) | ||||
Impact of Change [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Service cost | (400,000) | ||||
Interest cost | (3,300,000) | ||||
Impact of Change [Member] | Pension [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Service cost | (400,000) | ||||
Interest cost | (3,200,000) | ||||
Impact of Change [Member] | Pension [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Service cost | (400,000) | ||||
Interest cost | (3,200,000) | ||||
Impact of Change [Member] | Postretirement [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Service cost | 0 | ||||
Interest cost | (100,000) | ||||
Impact of Change [Member] | Postretirement [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Service cost | 0 | ||||
Interest cost | $ (100,000) | ||||
Adjustments for New Accounting Pronouncement [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Deferred Finance Costs, Current, Net | 2,100,000 | ||||
Deferred Finance Costs, Noncurrent, Net | 14,000,000 | ||||
Adjustments for New Accounting Pronouncement [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Deferred Finance Costs, Current, Net | 1,800,000 | ||||
Deferred Finance Costs, Noncurrent, Net | 4,500,000 | ||||
Line of Credit [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Deferred Finance Costs, Noncurrent, Net | 3,100,000 | ||||
Line of Credit [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Deferred Finance Costs, Noncurrent, Net | $ 700,000 |
Overview and Summary of Signfic
Overview and Summary of Signficant Accounting Policies (Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Excise Taxes Collected | $ 50.9 | $ 49.9 | $ 50.8 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Excise Taxes Collected | $ 50.9 | $ 49.9 | $ 50.8 |
Supplemental Financial Inform47
Supplemental Financial Information (Supplemental Financial Information) (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Supplemental Financial Information [Line Items] | ||
Unbilled revenue | $ 43 | $ 43.3 |
Customer receivables | 73.9 | 56.4 |
Amounts due from partners in jointly owned stations | 12.7 | 16 |
Other | 6.7 | 6 |
Provision for uncollectible accounts | (1.2) | (0.8) |
Total accounts receivable, net | 135.1 | 120.9 |
Fuel and Limestone | 38.9 | 72.2 |
Plant materials and supplies | 36.6 | 34.9 |
Other | 1.7 | 2 |
Total inventories, at average cost | 77.2 | 109.1 |
Assets held for sale - current | 0 | 62.2 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Supplemental Financial Information [Line Items] | ||
Unbilled revenue | 43 | 43.3 |
Customer receivables | 71.2 | 54.1 |
Amounts due from partners in jointly owned stations | 12.7 | 16 |
Other | 8.9 | 6.9 |
Provision for uncollectible accounts | (1.2) | (0.8) |
Total accounts receivable, net | 134.6 | 119.5 |
Fuel and Limestone | 38.8 | 72.2 |
Plant materials and supplies | 35.3 | 33.7 |
Other | 1.7 | 2.1 |
Total inventories, at average cost | $ 75.8 | 108 |
Accounts Receivable [Member] | ||
Supplemental Financial Information [Line Items] | ||
Assets held for sale - current | $ 31 |
Supplemental Financial Inform48
Supplemental Financial Information (Reclassification out of ACOI) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||
Other income | $ (109.4) | $ (121.5) | $ (158.1) |
Interest Expense | (106.1) | (118.3) | (126.6) |
Revenue | 1,427.3 | 1,612.8 | 1,716.5 |
Purchased Power | (417.4) | (562.6) | (587.9) |
Tax expense (benefit) | 278.8 | (20) | (15.4) |
Net income (loss) | (485.2) | (239) | (74.6) |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||
Other income | (25) | (36.3) | (34.1) |
Interest Expense | (24.5) | (30.9) | (33.9) |
Revenue | 1,365.9 | 1,552.3 | 1,668.3 |
Purchased Power | (414.1) | (555.7) | (582.4) |
Tax expense (benefit) | 422.4 | (35.1) | (39.7) |
Net income (loss) | (772.7) | 106.4 | 115 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||
Net income (loss) | (28.7) | (9.8) | 17.1 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||
Net income (loss) | (24.1) | (6.1) | 18.3 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Investment Gain (Loss) Attributable to Parent [Member] | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||
Other income | 0 | 0 | 0.4 |
Tax expense (benefit) | 0 | 0 | (0.2) |
Net income (loss) | 0 | 0 | 0.2 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Investment Gain (Loss) Attributable to Parent [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||
Other income | 0 | 0 | 0.4 |
Tax expense (benefit) | 0 | 0 | (0.2) |
Net income (loss) | 0 | 0 | 0.2 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||
Interest Expense | (1) | (1.1) | (1.3) |
Revenue | (55.3) | (18.7) | 28.4 |
Purchased Power | 9.9 | 4.4 | (0.7) |
Total before income taxes | (46.4) | (15.4) | 26.4 |
Tax expense (benefit) | 16.7 | 5.4 | (9.5) |
Net income (loss) | (29.7) | (10) | 16.9 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||
Interest Expense | (1) | (1.1) | (1.1) |
Revenue | (55.3) | (18.7) | 28.4 |
Purchased Power | 9.9 | 4.4 | (0.4) |
Total before income taxes | (46.4) | (15.4) | 26.9 |
Tax expense (benefit) | 16.4 | 5.6 | (11.5) |
Net income (loss) | (30) | (9.8) | 15.4 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||
Other income | 1.6 | 0.4 | 0 |
Tax expense (benefit) | (0.6) | (0.2) | 0 |
Net income (loss) | 1 | 0.2 | 0 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||
Other income | 7.7 | 5.6 | 4.1 |
Tax expense (benefit) | (1.8) | (1.9) | (1.4) |
Net income (loss) | $ 5.9 | $ 3.7 | $ 2.7 |
Supplemental Financial Inform49
Supplemental Financial Information (Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
AOCI Attributable to Parent, Net of Tax [Roll Forward] | |||
Balance, beginning of period | $ 17.4 | $ 7.5 | |
Other comprehensive income / (loss) before reclassifications | 11.6 | 19.7 | |
Amounts reclassified from accumulated other comprehensive income / (loss) | (28.7) | (9.8) | |
Other comprehensive income / (loss) | (17.1) | 9.9 | $ (17.1) |
Balance, end of period | 0.3 | 17.4 | 7.5 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | |||
Balance, beginning of period | (28.7) | (42.3) | |
Other comprehensive income / (loss) before reclassifications | 10.3 | 19.7 | |
Amounts reclassified from accumulated other comprehensive income / (loss) | (24.1) | (6.1) | |
Other comprehensive income / (loss) | (13.8) | 13.6 | (15.6) |
Balance, end of period | (42.5) | (28.7) | (42.3) |
Accumulated Net Investment Gain (Loss) Attributable to Parent [Member] | |||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | |||
Balance, beginning of period | 0.4 | 0.5 | |
Other comprehensive income / (loss) before reclassifications | 0.2 | (0.1) | |
Amounts reclassified from accumulated other comprehensive income / (loss) | 0 | 0 | |
Other comprehensive income / (loss) | 0.2 | (0.1) | |
Balance, end of period | 0.6 | 0.4 | 0.5 |
Accumulated Net Investment Gain (Loss) Attributable to Parent [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | |||
Balance, beginning of period | 0.5 | 0.7 | |
Other comprehensive income / (loss) before reclassifications | 0.2 | (0.2) | |
Amounts reclassified from accumulated other comprehensive income / (loss) | 0 | 0 | |
Other comprehensive income / (loss) | 0.2 | (0.2) | |
Balance, end of period | 0.7 | 0.5 | 0.7 |
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | |||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | |||
Balance, beginning of period | 26.7 | 18.5 | |
Other comprehensive income / (loss) before reclassifications | 16.1 | 18.2 | |
Amounts reclassified from accumulated other comprehensive income / (loss) | (29.7) | (10) | |
Other comprehensive income / (loss) | (13.6) | 8.2 | |
Balance, end of period | 13.1 | 26.7 | 18.5 |
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | |||
Balance, beginning of period | 11.2 | 2.8 | |
Other comprehensive income / (loss) before reclassifications | 16.1 | 18.2 | |
Amounts reclassified from accumulated other comprehensive income / (loss) | (30) | (9.8) | |
Other comprehensive income / (loss) | (13.9) | 8.4 | |
Balance, end of period | (2.7) | 11.2 | 2.8 |
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] | |||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | |||
Balance, beginning of period | (9.7) | (11.5) | |
Other comprehensive income / (loss) before reclassifications | (4.7) | 1.6 | |
Amounts reclassified from accumulated other comprehensive income / (loss) | 1 | 0.2 | |
Other comprehensive income / (loss) | (3.7) | 1.8 | |
Balance, end of period | (13.4) | (9.7) | (11.5) |
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | |||
Balance, beginning of period | (40.4) | (45.8) | |
Other comprehensive income / (loss) before reclassifications | (6) | 1.7 | |
Amounts reclassified from accumulated other comprehensive income / (loss) | 5.9 | 3.7 | |
Other comprehensive income / (loss) | (0.1) | 5.4 | |
Balance, end of period | $ (40.5) | $ (40.4) | $ (45.8) |
Regulatory Assets and Liabili50
Regulatory Assets and Liabilities (Narrative) (Details) | Mar. 08, 2017USD ($)kWh | Jan. 30, 2017USD ($) | Oct. 11, 2016USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) |
Distribution Modernization Rider | $ 145,000,000 | ||||
Distribution Modernization Rider Period | 7 years | ||||
Regulatory Assets, Renewable Energy Recovery | $ 10,500,000 | ||||
Energy Efficiency Rider Revenue | $ 20,100,000 | ||||
Regulatory Assets | 204,000,000 | $ 194,300,000 | |||
Regulatory Liabilities | 164,100,000 | 151,400,000 | |||
EERider shared savings incentive accrual, after tax | $ 4,500,000 | ||||
Reconciliation rider as percent of costs in excess of base amount of Fuel, RPM, Alternative Energy and Competitive Bidding riders (percent) | 10.00% | ||||
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Distribution Modernization Rider | $ 145,000,000 | ||||
Distribution Modernization Rider Period | 7 years | ||||
Regulatory Assets, Renewable Energy Recovery | $ 10,500,000 | ||||
Energy Efficiency Rider Revenue | $ 20,100,000 | ||||
Regulatory Assets | 204,000,000 | 194,300,000 | |||
Regulatory Liabilities | 164,100,000 | $ 151,400,000 | |||
EERider shared savings incentive accrual, after tax | $ 4,500,000 | ||||
Reconciliation rider as percent of costs in excess of base amount of Fuel, RPM, Alternative Energy and Competitive Bidding riders (percent) | 10.00% | ||||
Subsequent Event [Member] | |||||
Distribution Modernization Rider | $ 90,000,000 | ||||
Distribution Modernization Rider Period | 5 years | ||||
Distribution Investment Rider | $ 35,000,000 | ||||
Residential Customer KWh Usage | kWh | 1,000 | ||||
Monthly Bill Increase | $ 2.39 | ||||
ESP 3 Settlement Time Period | 6 years | ||||
Subsequent Event [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Distribution Modernization Rider | $ 90,000,000 | ||||
Distribution Modernization Rider Period | 5 years | ||||
Distribution Investment Rider | $ 35,000,000 | ||||
Residential Customer KWh Usage | kWh | 1,000 | ||||
Monthly Bill Increase | $ 2.39 | ||||
ESP 3 Settlement Time Period | 6 years |
Regulatory Assets and Liabili51
Regulatory Assets and Liabilities (Schedule of Regulatory Assets and Liabilities) (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Total current regulatory assets | $ 100,000 | $ 14,400,000 |
Total non-current regulatory assets | 203,900,000 | 179,900,000 |
Total regulatory assets | 204,000,000 | 194,300,000 |
Total current regulatory liabilities | 33,700,000 | 24,400,000 |
Total non-current regulatory liabilities | 130,400,000 | 127,000,000 |
Total regulatory liabilities | 164,100,000 | 151,400,000 |
Energy efficiency program [Member] | ||
Total current regulatory liabilities | 14,100,000 | 9,200,000 |
Competitive bidding [Member] | ||
Total current regulatory liabilities | 16,100,000 | 9,100,000 |
Transmission costs [Member] | ||
Total current regulatory liabilities | 3,300,000 | 3,700,000 |
Reconciliation rider [Member] | ||
Total current regulatory liabilities | 0 | 2,100,000 |
Other miscellaneous [Member] | ||
Total current regulatory liabilities | 200,000 | 300,000 |
Estimated costs of removal - regulated property [Member] | ||
Total non-current regulatory liabilities | 126,500,000 | 121,800,000 |
Postretirement benefits [Member] | ||
Total non-current regulatory liabilities | 3,900,000 | 5,200,000 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total current regulatory assets | 100,000 | 14,400,000 |
Total non-current regulatory assets | 203,900,000 | 179,900,000 |
Total regulatory assets | 204,000,000 | 194,300,000 |
Total current regulatory liabilities | 33,700,000 | 24,400,000 |
Total non-current regulatory liabilities | 130,400,000 | 127,000,000 |
Total regulatory liabilities | 164,100,000 | 151,400,000 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Energy efficiency program [Member] | ||
Total current regulatory liabilities | 14,100,000 | 9,200,000 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Competitive bidding [Member] | ||
Total current regulatory liabilities | 16,100,000 | 9,100,000 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Transmission costs [Member] | ||
Total current regulatory liabilities | 3,300,000 | 3,700,000 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Reconciliation rider [Member] | ||
Total current regulatory liabilities | 0 | 2,100,000 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Other miscellaneous [Member] | ||
Total current regulatory liabilities | 200,000 | 300,000 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Estimated costs of removal - regulated property [Member] | ||
Total non-current regulatory liabilities | 126,500,000 | 121,800,000 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Postretirement benefits [Member] | ||
Total non-current regulatory liabilities | $ 3,900,000 | 5,200,000 |
Fuel and purchased power recovery costs [Member] | ||
Type of Recovery | A | |
Amortization Through | P2016Y | |
Total current regulatory assets | $ 0 | 13,900,000 |
Fuel and purchased power recovery costs [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Type of Recovery | A | |
Amortization Through | P2016Y | |
Total current regulatory assets | $ 0 | 13,900,000 |
Economic development costs [Member] | ||
Type of Recovery | A | |
Amortization Through | P2017Y | |
Total current regulatory assets | $ 100,000 | 500,000 |
Economic development costs [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Type of Recovery | A | |
Amortization Through | P2017Y | |
Total current regulatory assets | $ 100,000 | 500,000 |
Pension benefits [Member] | ||
Type of Recovery | B | |
Amortization Through | Ongoing | |
Total non-current regulatory assets | $ 97,600,000 | 91,600,000 |
Pension benefits [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Type of Recovery | B | |
Amortization Through | Ongoing | |
Total non-current regulatory assets | $ 97,600,000 | 91,600,000 |
Deferred recoverable income taxes [Member] | ||
Type of Recovery | B/C | |
Amortization Through | Ongoing | |
Total non-current regulatory assets | $ 35,900,000 | 36,400,000 |
Deferred recoverable income taxes [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Type of Recovery | B/C | |
Amortization Through | Ongoing | |
Total non-current regulatory assets | $ 35,900,000 | 36,400,000 |
Fuel costs [Member] | ||
Type of Recovery | B | |
Amortization Through | Undetermined | |
Total non-current regulatory assets | $ 15,400,000 | 12,700,000 |
Fuel costs [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Type of Recovery | B | |
Amortization Through | Undetermined | |
Total non-current regulatory assets | $ 15,400,000 | 12,700,000 |
Unrecovered OVEC charges [Member] | ||
Type of Recovery | D | |
Amortization Through | Undetermined | |
Total non-current regulatory assets | $ 21,000,000 | 10,500,000 |
Unrecovered OVEC charges [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Type of Recovery | D | |
Amortization Through | Undetermined | |
Total non-current regulatory assets | $ 21,000,000 | 10,500,000 |
Unamortized loss on reacquired debt [Member] | ||
Type of Recovery | B | |
Amortization Through | Various | |
Total non-current regulatory assets | $ 8,000,000 | 9,000,000 |
Unamortized loss on reacquired debt [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Type of Recovery | B | |
Amortization Through | Various | |
Total non-current regulatory assets | $ 8,000,000 | 9,000,000 |
Smart grid and advanced metering infrastructure costs [Member] | ||
Type of Recovery | D | |
Amortization Through | Undetermined | |
Total non-current regulatory assets | $ 7,300,000 | 7,300,000 |
Smart grid and advanced metering infrastructure costs [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Type of Recovery | D | |
Amortization Through | Undetermined | |
Total non-current regulatory assets | $ 7,300,000 | 7,300,000 |
Generation separation costs [Member] | ||
Type of Recovery | D | |
Amortization Through | Undetermined | |
Total non-current regulatory assets | $ 5,700,000 | 3,900,000 |
Generation separation costs [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Amortization Through | Undetermined | |
Total non-current regulatory assets | $ 5,700,000 | 3,900,000 |
Retail settlement system costs [Member] | ||
Type of Recovery | D | |
Amortization Through | Undetermined | |
Total non-current regulatory assets | $ 3,100,000 | 3,100,000 |
Retail settlement system costs [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Type of Recovery | D | |
Amortization Through | Undetermined | |
Total non-current regulatory assets | $ 3,100,000 | 3,100,000 |
Consumer education campaign [Member] | ||
Type of Recovery | D | |
Amortization Through | Undetermined | |
Total non-current regulatory assets | $ 3,000,000 | 3,000,000 |
Consumer education campaign [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Type of Recovery | D | |
Amortization Through | Undetermined | |
Total non-current regulatory assets | $ 3,000,000 | 3,000,000 |
Rate case costs [Member] | ||
Type of Recovery | D | |
Amortization Through | Undetermined | |
Total non-current regulatory assets | $ 6,300,000 | 1,900,000 |
Rate case costs [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Type of Recovery | D | |
Total non-current regulatory assets | $ 6,300,000 | 1,900,000 |
Other miscellaneous [Member] | ||
Type of Recovery | D | |
Amortization Through | Undetermined | |
Total non-current regulatory assets | $ 600,000 | 500,000 |
Other miscellaneous [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Type of Recovery | D | |
Amortization Through | Undetermined | |
Total non-current regulatory assets | $ 600,000 | $ 500,000 |
Property, Plant and Equipment w
Property, Plant and Equipment with Corresponding Depreciation Rates (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Public Utility, Property, Plant and Equipment [Line Items] | |||
Total property, plant and equipment in service | $ 1,985.6 | $ 2,850.7 | |
Total property, plant and equipment in service, Composite Rate | 6.10% | 4.40% | 5.30% |
Regulated Operation [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Transmission | $ 247.3 | $ 239.4 | |
Distribution | 1,141.1 | 1,085.7 | |
General | 13.7 | 13.9 | |
Non-depreciable | 63.5 | 62.5 | |
Total property, plant and equipment in service | $ 1,465.6 | $ 1,401.5 | |
Transmission, Composite Rate | 3.90% | 3.90% | |
Distribution, Composite Rate | 4.70% | 5.00% | |
General, Composite Rate | 7.40% | 7.20% | |
Unregulated Operation [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Non-depreciable | $ 19.8 | $ 19.8 | |
Total property, plant and equipment in service | 520 | 1,449.2 | |
Production / Generation | $ 483.2 | $ 1,413.1 | |
Production/Generation, Composite Rate | 11.70% | 4.20% | |
Other | $ 17 | $ 16.3 | |
Other, Composite Rate | 8.00% | 12.10% | |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Total property, plant and equipment in service | $ 2,398.6 | $ 5,172.3 | |
Total property, plant and equipment in service, Composite Rate | 4.60% | 2.50% | 2.80% |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Regulated Operation [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Transmission | $ 421.1 | $ 413.7 | |
Distribution | 1,693.5 | 1,639.7 | |
General | 31.6 | 31.6 | |
Non-depreciable | 63.5 | 62.5 | |
Total property, plant and equipment in service | $ 2,209.7 | $ 2,147.5 | |
Transmission, Composite Rate | 2.30% | 2.30% | |
Distribution, Composite Rate | 3.20% | 3.30% | |
General, Composite Rate | 3.20% | 3.20% | |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Unregulated Operation [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Non-depreciable | $ 188.9 | $ 3,024.8 | |
Production / Generation | $ 173.9 | $ 3,009.8 | |
Production/Generation, Composite Rate | 26.20% | 2.10% | |
Other | $ 15 | $ 15 |
Property, Plant and Equipment53
Property, Plant and Equipment (Narrative) (Details) $ in Millions | 6 Months Ended | 12 Months Ended | ||
Dec. 31, 2016USD ($) | Dec. 31, 2016USD ($)generating_facility | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | |
Jointly Owned Utility Plant Interests [Line Items] | ||||
Number of generating facilities | generating_facility | 5 | |||
Fixed-asset impairment (Note 15) | $ 623.5 | $ 859 | $ 0 | $ 11.5 |
Estimated costs of removal | 126.5 | $ 126.5 | 121.8 | 119.3 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Jointly Owned Utility Plant Interests [Line Items] | ||||
Number of generating facilities | generating_facility | 5 | |||
Fixed-asset impairment (Note 15) | 496.4 | $ 1,353.5 | 0 | 0 |
Estimated costs of removal | $ 126.5 | $ 126.5 | $ 121.8 | $ 119.3 |
Property, Plant and Equipment54
Property, Plant and Equipment (Ownership Interests) (Details) $ in Millions | 3 Months Ended | 12 Months Ended |
Mar. 31, 2014MW | Dec. 31, 2016USD ($)MW | |
THE DAYTON POWER AND LIGHT COMPANY [Member] | East Bend Station [Member] | ||
Production Capacity (MW) | MW | 186 | |
DP&L Share [Member] | Conesville [Member] | ||
Ownership (%) | 16.50% | |
DP&L Share [Member] | Killen Station [Member] | ||
Ownership (%) | 67.00% | |
DP&L Share [Member] | Miami Fort Units 7 and 8 [Member] | ||
Ownership (%) | 36.00% | |
DP&L Share [Member] | Stuart Station [Member] | ||
Ownership (%) | 35.00% | |
DP&L Share [Member] | Zimmer Station [Member] | ||
Ownership (%) | 28.10% | |
DP&L Share [Member] | Total Jointly-owned Stations [Member] | ||
Production Capacity (MW) | MW | 2,078 | |
DP&L Share [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Conesville [Member] | ||
Ownership (%) | 16.50% | |
Production Capacity (MW) | MW | 129 | |
DP&L Share [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Killen Station [Member] | ||
Ownership (%) | 67.00% | |
Production Capacity (MW) | MW | 402 | |
DP&L Share [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Miami Fort Units 7 and 8 [Member] | ||
Ownership (%) | 36.00% | |
Production Capacity (MW) | MW | 368 | |
DP&L Share [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Stuart Station [Member] | ||
Ownership (%) | 35.00% | |
Production Capacity (MW) | MW | 808 | |
DP&L Share [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Zimmer Station [Member] | ||
Ownership (%) | 28.10% | |
Production Capacity (MW) | MW | 371 | |
DP&L Share [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Total Jointly-owned Stations [Member] | ||
Production Capacity (MW) | MW | 2,078 | |
DP&L Investment [Member] | Conesville [Member] | ||
Gross Plant In Service | $ 0 | |
Accumulated Depreciation | 0 | |
Construction Work in Process | 0 | |
DP&L Investment [Member] | Killen Station [Member] | ||
Gross Plant In Service | 34 | |
Accumulated Depreciation | 0 | |
Construction Work in Process | 2 | |
DP&L Investment [Member] | Miami Fort Units 7 and 8 [Member] | ||
Gross Plant In Service | 27 | |
Accumulated Depreciation | 0 | |
Construction Work in Process | 7 | |
DP&L Investment [Member] | Stuart Station [Member] | ||
Gross Plant In Service | 24 | |
Accumulated Depreciation | 0 | |
Construction Work in Process | 23 | |
DP&L Investment [Member] | Zimmer Station [Member] | ||
Gross Plant In Service | 7 | |
Accumulated Depreciation | 0 | |
Construction Work in Process | 9 | |
DP&L Investment [Member] | Transmission (At Varying Percentages) [Member] | ||
Gross Plant In Service | 43 | |
Accumulated Depreciation | 10 | |
DP&L Investment [Member] | Total Jointly-owned Stations [Member] | ||
Gross Plant In Service | 135 | |
Accumulated Depreciation | 10 | |
Construction Work in Process | 41 | |
DP&L Investment [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Conesville [Member] | ||
Gross Plant In Service | 0 | |
Accumulated Depreciation | 0 | |
Construction Work in Process | 0 | |
DP&L Investment [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Killen Station [Member] | ||
Gross Plant In Service | 34 | |
Accumulated Depreciation | 0 | |
Construction Work in Process | 2 | |
DP&L Investment [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Miami Fort Units 7 and 8 [Member] | ||
Gross Plant In Service | 27 | |
Accumulated Depreciation | 0 | |
Construction Work in Process | 7 | |
DP&L Investment [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Stuart Station [Member] | ||
Gross Plant In Service | 24 | |
Accumulated Depreciation | 0 | |
Construction Work in Process | 23 | |
DP&L Investment [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Zimmer Station [Member] | ||
Gross Plant In Service | 7 | |
Accumulated Depreciation | 0 | |
Construction Work in Process | 9 | |
DP&L Investment [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Transmission (At Varying Percentages) [Member] | ||
Gross Plant In Service | 99 | |
Accumulated Depreciation | 66 | |
DP&L Investment [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Total Jointly-owned Stations [Member] | ||
Gross Plant In Service | 191 | |
Accumulated Depreciation | 66 | |
Construction Work in Process | $ 41 |
Property, Plant and Equipment
Property, Plant and Equipment (Changes in the Liability for Generation of AROs) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Balance at January 1 | $ 65.9 | $ 26.9 |
Additions | 70.2 | 40.3 |
Accretion expense | 2.7 | 1.9 |
Settlements | 0 | (3.2) |
Balance at December 31 | 138.8 | 65.9 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Balance at January 1 | 62.1 | 22.9 |
Additions | 70.2 | 40.3 |
Accretion expense | 2.9 | 2.1 |
Settlements | 0 | (3.2) |
Balance at December 31 | $ 135.2 | $ 62.1 |
Property, Plant and Equipment56
Property, Plant and Equipment (Changes in the Liability for Transmission and Distribution Asset Removal Costs) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Changes in Liability for Transmission and Distribution Asset Removal Costs [Roll Forward] | ||
Balance at January 1 | $ 121.8 | $ 119.3 |
Additions | 11.7 | 24.3 |
Settlements | (7) | (21.8) |
Balance at December 31 | 126.5 | 121.8 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Changes in Liability for Transmission and Distribution Asset Removal Costs [Roll Forward] | ||
Balance at January 1 | 121.8 | 119.3 |
Additions | 11.7 | 24.3 |
Settlements | (7) | (21.8) |
Balance at December 31 | $ 126.5 | $ 121.8 |
Fair Value Measurements (Narrat
Fair Value Measurements (Narrative) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Debt maturity date, earliest | 2,019 | |
Debt maturity date, latest | 2,061 | |
Unrealized gains and immaterial losses on Master Trust assets in AOCI | $ 1 | $ 0.7 |
Unrealized gains and immaterial losses on Master Trust assets in AOCI, after tax | $ 0.6 | 0.5 |
Percent of inputs to the fair value of derivative instruments from quoted market prices | 95.00% | |
Gross additions to our existing landfill and asbestos AROs | $ 72.9 | 39 |
Gross additions to our existing landfill and asbestos AROs, after tax | 47.4 | 25.4 |
Increase (Decrease) in Asset Retirement Obligations | 40.3 | |
Increase (Decrease) in Asset Retirement Obligations after tax | (26.2) | |
Available-for-sale Securities, Gross Realized Gains (Losses), Sale Proceeds | 2.6 | |
AvailableForSaleSecuritiesGross Realized Gains Losses Sale Proceeds Net of Tax | 1.7 | |
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Unrealized gains and immaterial losses on Master Trust assets in AOCI | 1.1 | 0.8 |
Unrealized gains and immaterial losses on Master Trust assets in AOCI, after tax | $ 0.7 | 0.5 |
Percent of inputs to the fair value of derivative instruments from quoted market prices | 95.00% | |
Gross additions to our existing landfill and asbestos AROs | $ 73.1 | 39.2 |
Gross additions to our existing landfill and asbestos AROs, after tax | 47.5 | $ 25.5 |
Increase (Decrease) in Asset Retirement Obligations | 40.3 | |
Increase (Decrease) in Asset Retirement Obligations after tax | (26.2) | |
Available-for-sale Securities, Gross Realized Gains (Losses), Sale Proceeds | 2.6 | |
AvailableForSaleSecuritiesGross Realized Gains Losses Sale Proceeds Net of Tax | 1.7 | |
Stuart and Killen [Member] | ||
Gross additions to our existing landfill and asbestos AROs | 67.9 | |
Gross additions to our existing landfill and asbestos AROs, after tax | 44.1 | |
Stuart and Killen [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Gross additions to our existing landfill and asbestos AROs | 67.9 | |
Gross additions to our existing landfill and asbestos AROs, after tax | $ 44.1 |
Fair Value Measurements (Fair V
Fair Value Measurements (Fair Value and Cost of Non-Derivative Instruments) (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Hedge Funds [Member] | ||
Total Master Trust Assets, Fair Value | $ 0 | |
Carrying Value [Member] | ||
Total Assets | $ 7.6 | 8.3 |
Carrying Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Assets | 7.6 | 8.3 |
Carrying Value [Member] | Money Market Funds [Member] | ||
Total Master Trust Assets, Cost | 0.4 | 0.2 |
Carrying Value [Member] | Money Market Funds [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Cost | 0.4 | 0.2 |
Carrying Value [Member] | Equity Securities [Member] | ||
Total Master Trust Assets, Cost | 2.4 | 3 |
Carrying Value [Member] | Equity Securities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Cost | 2.4 | 3 |
Carrying Value [Member] | Debt Securities [Member] | ||
Total Master Trust Assets, Cost | 4.4 | 4.4 |
Carrying Value [Member] | Debt Securities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Cost | 4.4 | 4.4 |
Carrying Value [Member] | Hedge Funds [Member] | ||
Total Master Trust Assets, Cost | 0 | 0.4 |
Carrying Value [Member] | Hedge Funds [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Cost | 0 | 0.4 |
Carrying Value [Member] | Real Estate Funds [Member] | ||
Total Master Trust Assets, Cost | 0.3 | 0.3 |
Carrying Value [Member] | Real Estate Funds [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Cost | 0.3 | 0.3 |
Carrying Value [Member] | Tangible Assets [Member] | ||
Total Master Trust Assets, Cost | 0.1 | 0 |
Carrying Value [Member] | Tangible Assets [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Cost | 0.1 | 0 |
Carrying Value [Member] | Debt [Member] | ||
Long-term Debt | 1,858.4 | 1,993.3 |
Carrying Value [Member] | Debt [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Long-term Debt | 749.4 | 756.7 |
Fair Value [Member] | ||
Total Master Trust Assets, Fair Value | 8.7 | 9 |
Total Assets | 8.7 | 9 |
Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 8.7 | 9 |
Total Assets | 8.7 | 9 |
Fair Value [Member] | Money Market Funds [Member] | ||
Total Master Trust Assets, Fair Value | 0.4 | 0.2 |
Fair Value [Member] | Money Market Funds [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0.4 | 0.2 |
Fair Value [Member] | Equity Securities [Member] | ||
Total Master Trust Assets, Fair Value | 3.4 | 3.8 |
Fair Value [Member] | Equity Securities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 3.4 | 3.8 |
Fair Value [Member] | Debt Securities [Member] | ||
Total Master Trust Assets, Fair Value | 4.4 | 4.3 |
Fair Value [Member] | Debt Securities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 4.4 | 4.3 |
Fair Value [Member] | Hedge Funds [Member] | ||
Total Master Trust Assets, Fair Value | 0.1 | 0.4 |
Fair Value [Member] | Hedge Funds [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0.1 | 0.4 |
Fair Value [Member] | Real Estate Funds [Member] | ||
Total Master Trust Assets, Fair Value | 0.3 | 0.3 |
Fair Value [Member] | Real Estate Funds [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0.3 | 0.3 |
Fair Value [Member] | Tangible Assets [Member] | ||
Total Master Trust Assets, Fair Value | 0.1 | 0 |
Fair Value [Member] | Tangible Assets [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0.1 | 0 |
Fair Value [Member] | Debt [Member] | ||
Debt, Fair Value | 1,907.7 | 1,975.3 |
Fair Value [Member] | Debt [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Debt, Fair Value | $ 763.5 | $ 764.2 |
Fair Value Measurements (Fair59
Fair Value Measurements (Fair Value of Assets and Liabilities Measured on Recurring Basis) (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Fair Value, Inputs, Level 1 [Member] | ||
Total Master Trust Assets, Fair Value | $ 0.4 | $ 0.2 |
Total Derivative Assets | 0 | 0 |
Total Assets | 0.4 | 0.2 |
Total Derivative Liabilities | 0 | 0 |
Total Liabilities | 0 | 0 |
Fair Value, Inputs, Level 1 [Member] | Forward Contract Power [Member] | ||
Total Derivative Assets | 0 | 0 |
Total Derivative Liabilities | 0 | 0 |
Fair Value, Inputs, Level 1 [Member] | Interest Rate Contract [Member] | ||
Total Derivative Assets | 0 | |
Total Derivative Liabilities | 0 | |
Fair Value, Inputs, Level 1 [Member] | Commodity Contract - FTR [Member] | ||
Total Derivative Assets | 0 | 0 |
Total Derivative Liabilities | 0 | 0 |
Fair Value, Inputs, Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0.4 | 0.2 |
Total Derivative Assets | 0 | 0 |
Total Assets | 0.4 | 0.2 |
Total Derivative Liabilities | 0 | 0 |
Debt Instrument, Fair Value Disclosure | 0 | 0 |
Total Liabilities | 0 | 0 |
Fair Value, Inputs, Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member] | ||
Total Derivative Assets | 0 | 0 |
Total Derivative Liabilities | 0 | 0 |
Fair Value, Inputs, Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Interest Rate Contract [Member] | ||
Total Derivative Assets | 0 | |
Total Derivative Liabilities | 0 | |
Fair Value, Inputs, Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - FTR [Member] | ||
Total Derivative Assets | 0 | 0 |
Total Derivative Liabilities | 0 | 0 |
Fair Value, Inputs, Level 2 [Member] | ||
Total Master Trust Assets, Fair Value | 8.3 | 8.8 |
Total Derivative Assets | 20.7 | 30.5 |
Total Assets | 29 | 39.3 |
Total Derivative Liabilities | 26.7 | 23.9 |
Total Liabilities | 1,916.4 | 1,981.1 |
Fair Value, Inputs, Level 2 [Member] | Forward Contract Power [Member] | ||
Total Derivative Assets | 19.5 | 30.5 |
Total Derivative Liabilities | 26 | 23.9 |
Fair Value, Inputs, Level 2 [Member] | Interest Rate Contract [Member] | ||
Total Derivative Assets | 1.2 | |
Total Derivative Liabilities | 0.7 | |
Fair Value, Inputs, Level 2 [Member] | Commodity Contract - FTR [Member] | ||
Total Derivative Assets | 0 | 0 |
Total Derivative Liabilities | 0 | 0 |
Fair Value, Inputs, Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 8.3 | 8.8 |
Total Derivative Assets | 20.7 | 30.6 |
Total Assets | 29 | 39.4 |
Total Derivative Liabilities | 26.7 | 23.9 |
Debt Instrument, Fair Value Disclosure | 745.5 | 746.1 |
Total Liabilities | 772.2 | 770 |
Fair Value, Inputs, Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member] | ||
Total Derivative Assets | 19.5 | 30.6 |
Total Derivative Liabilities | 26 | 23.9 |
Fair Value, Inputs, Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Interest Rate Contract [Member] | ||
Total Derivative Assets | 1.2 | |
Total Derivative Liabilities | 0.7 | |
Fair Value, Inputs, Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - FTR [Member] | ||
Total Derivative Assets | 0 | 0 |
Total Derivative Liabilities | 0 | 0 |
Fair Value, Inputs, Level 3 [Member] | ||
Total Derivative Assets | 0.1 | 0.2 |
Total Assets | 0.1 | 0.2 |
Total Derivative Liabilities | 2.5 | 3.6 |
Total Liabilities | 20.5 | 21.7 |
Fair Value, Inputs, Level 3 [Member] | Forward Contract Power [Member] | ||
Total Derivative Assets | 0 | 0 |
Total Derivative Liabilities | 2.5 | 3.1 |
Fair Value, Inputs, Level 3 [Member] | Interest Rate Contract [Member] | ||
Total Derivative Assets | 0 | |
Total Derivative Liabilities | 0 | |
Fair Value, Inputs, Level 3 [Member] | Commodity Contract - FTR [Member] | ||
Total Derivative Assets | 0.1 | 0.2 |
Total Derivative Liabilities | 0 | 0.5 |
Fair Value, Inputs, Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Derivative Assets | 0.1 | 0.2 |
Total Assets | 0.1 | 0.2 |
Total Derivative Liabilities | 2.5 | 3.6 |
Debt Instrument, Fair Value Disclosure | 18 | 18.1 |
Total Liabilities | 20.5 | 21.7 |
Fair Value, Inputs, Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member] | ||
Total Derivative Assets | 0 | 0 |
Total Derivative Liabilities | 2.5 | 3.1 |
Fair Value, Inputs, Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Interest Rate Contract [Member] | ||
Total Derivative Assets | 0 | |
Total Derivative Liabilities | 0 | |
Fair Value, Inputs, Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - FTR [Member] | ||
Total Derivative Assets | 0.1 | 0.2 |
Total Derivative Liabilities | 0 | 0.5 |
Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Total Master Trust Assets, Fair Value | 0 | 0 |
Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0 | 0 |
Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Total Master Trust Assets, Fair Value | 3.4 | 3.8 |
Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 3.4 | 3.8 |
Debt Securities [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Total Master Trust Assets, Fair Value | 0 | 0 |
Debt Securities [Member] | Fair Value, Inputs, Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0 | 0 |
Debt Securities [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Total Master Trust Assets, Fair Value | 4.4 | 4.3 |
Debt Securities [Member] | Fair Value, Inputs, Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 4.4 | 4.3 |
Money Market Funds [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Total Master Trust Assets, Fair Value | 0.4 | 0.2 |
Money Market Funds [Member] | Fair Value, Inputs, Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0.4 | 0.2 |
Money Market Funds [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Total Master Trust Assets, Fair Value | 0 | 0 |
Money Market Funds [Member] | Fair Value, Inputs, Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0 | 0 |
Hedge Funds [Member] | ||
Total Master Trust Assets, Fair Value | 0 | |
Hedge Funds [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Total Master Trust Assets, Fair Value | 0 | |
Hedge Funds [Member] | Fair Value, Inputs, Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0 | 0 |
Hedge Funds [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Total Master Trust Assets, Fair Value | 0.1 | 0.4 |
Hedge Funds [Member] | Fair Value, Inputs, Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0.1 | 0.4 |
Real Estate Funds [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Total Master Trust Assets, Fair Value | 0 | 0 |
Real Estate Funds [Member] | Fair Value, Inputs, Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0 | 0 |
Real Estate Funds [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Total Master Trust Assets, Fair Value | 0.3 | 0.3 |
Real Estate Funds [Member] | Fair Value, Inputs, Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0.3 | 0.3 |
Tangible Assets [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Total Master Trust Assets, Fair Value | 0 | |
Tangible Assets [Member] | Fair Value, Inputs, Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0 | |
Tangible Assets [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Total Master Trust Assets, Fair Value | 0.1 | |
Tangible Assets [Member] | Fair Value, Inputs, Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0.1 | |
Debt [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Debt Instrument, Fair Value Disclosure | 0 | 0 |
Debt [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Debt Instrument, Fair Value Disclosure | 1,889.7 | 1,957.2 |
Debt [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Debt Instrument, Fair Value Disclosure | 18 | 18.1 |
Fair Value [Member] | ||
Total Master Trust Assets, Fair Value | 8.7 | 9 |
Total Derivative Assets | 20.8 | 30.7 |
Total Assets | 29.5 | 39.7 |
Total Derivative Liabilities | 29.2 | 27.5 |
Total Liabilities | 1,936.9 | 2,002.8 |
Fair Value [Member] | Forward Contract Power [Member] | ||
Total Derivative Assets | 19.5 | 30.5 |
Total Derivative Liabilities | 28.5 | 27 |
Fair Value [Member] | Interest Rate Contract [Member] | ||
Total Derivative Assets | 1.2 | |
Total Derivative Liabilities | 0.7 | |
Fair Value [Member] | Commodity Contract - FTR [Member] | ||
Total Derivative Assets | 0.1 | 0.2 |
Total Derivative Liabilities | 0 | 0.5 |
Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 8.7 | 9 |
Total Derivative Assets | 20.8 | 30.8 |
Total Assets | 29.5 | 39.8 |
Total Derivative Liabilities | 29.2 | 27.5 |
Debt Instrument, Fair Value Disclosure | 763.5 | |
Total Liabilities | 792.7 | 791.7 |
Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member] | ||
Total Derivative Assets | 19.5 | 30.6 |
Total Derivative Liabilities | 28.5 | 27 |
Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Interest Rate Contract [Member] | ||
Total Derivative Assets | 1.2 | |
Total Derivative Liabilities | 0.7 | |
Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - FTR [Member] | ||
Total Derivative Assets | 0.1 | 0.2 |
Total Derivative Liabilities | 0 | 0.5 |
Fair Value [Member] | Equity Securities [Member] | ||
Total Master Trust Assets, Fair Value | 3.4 | 3.8 |
Fair Value [Member] | Equity Securities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 3.4 | 3.8 |
Fair Value [Member] | Debt Securities [Member] | ||
Total Master Trust Assets, Fair Value | 4.4 | 4.3 |
Fair Value [Member] | Debt Securities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 4.4 | 4.3 |
Fair Value [Member] | Money Market Funds [Member] | ||
Total Master Trust Assets, Fair Value | 0.4 | 0.2 |
Fair Value [Member] | Money Market Funds [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0.4 | 0.2 |
Fair Value [Member] | Hedge Funds [Member] | ||
Total Master Trust Assets, Fair Value | 0.1 | 0.4 |
Fair Value [Member] | Hedge Funds [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0.1 | 0.4 |
Fair Value [Member] | Real Estate Funds [Member] | ||
Total Master Trust Assets, Fair Value | 0.3 | 0.3 |
Fair Value [Member] | Real Estate Funds [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0.3 | 0.3 |
Fair Value [Member] | Tangible Assets [Member] | ||
Total Master Trust Assets, Fair Value | 0.1 | 0 |
Fair Value [Member] | Tangible Assets [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0.1 | 0 |
Fair Value [Member] | Debt [Member] | ||
Debt Instrument, Fair Value Disclosure | $ 1,907.7 | 1,975.3 |
Fair Value [Member] | Debt [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Debt Instrument, Fair Value Disclosure | $ 764.2 |
Fair Value Measurements (Fair60
Fair Value Measurements (Fair Value of Assets and Liabilities Measured on a Nonrecurring Basis) (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Mar. 31, 2015 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2016 | Jun. 30, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Carrying Value | $ 2,537.2 | $ 1,767.2 | $ 1,767.2 | $ 2,537.2 | ||||||||
Fixed-asset impairment (Note 15) | 623.5 | 859 | 0 | $ 11.5 | ||||||||
Goodwill impairment | [1] | 0 | 317 | 135.8 | ||||||||
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Carrying Value | 2,714 | 1,440.6 | 1,440.6 | 2,714 | ||||||||
Fixed-asset impairment (Note 15) | 496.4 | 1,353.5 | 0 | 0 | ||||||||
Goodwill | 0 | 0 | 317 | $ 317 | ||||||||
Goodwill impairment | $ 317 | $ 317 | $ 317 | |||||||||
DPLER [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Goodwill | $ 135.8 | $ 135.8 | ||||||||||
Goodwill impairment | $ 135.8 | 135.8 | ||||||||||
Killen [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Carrying Value | 118.2 | $ 315.1 | 118.2 | |||||||||
Fixed-asset impairment (Note 15) | 75.4 | 230.8 | ||||||||||
Killen [Member] | Fair Value, Inputs, Level 1 [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Long-lived assets held and used, fair value | 0 | 0 | 0 | |||||||||
Killen [Member] | Fair Value, Inputs, Level 2 [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Long-lived assets held and used, fair value | 0 | 0 | 0 | |||||||||
Killen [Member] | Fair Value, Inputs, Level 3 [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Long-lived assets held and used, fair value | 42.8 | 84.3 | 42.8 | |||||||||
Killen [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Carrying Value | 118.1 | 330.5 | 118.1 | |||||||||
Fixed-asset impairment (Note 15) | 75.3 | 246.2 | 246.2 | |||||||||
Killen [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Fair Value, Inputs, Level 3 [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Long-lived assets held and used, fair value | 42.8 | 84.3 | 42.8 | |||||||||
Stuart [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Carrying Value | 285.9 | 285.9 | ||||||||||
Fixed-asset impairment (Note 15) | 228.5 | |||||||||||
Stuart [Member] | Fair Value, Inputs, Level 1 [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Long-lived assets held and used, fair value | 0 | 0 | ||||||||||
Stuart [Member] | Fair Value, Inputs, Level 2 [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Long-lived assets held and used, fair value | 0 | 0 | ||||||||||
Stuart [Member] | Fair Value, Inputs, Level 3 [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Long-lived assets held and used, fair value | 57.4 | 57.4 | ||||||||||
Stuart [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Carrying Value | 207.3 | 456.4 | 207.3 | |||||||||
Fixed-asset impairment (Note 15) | 149.9 | 292 | 292 | |||||||||
Stuart [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Fair Value, Inputs, Level 3 [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Long-lived assets held and used, fair value | 57.4 | 164.4 | 57.4 | |||||||||
Miami Fort [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Carrying Value | 185.9 | 185.9 | ||||||||||
Fixed-asset impairment (Note 15) | 149.4 | |||||||||||
Miami Fort [Member] | Fair Value, Inputs, Level 1 [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Long-lived assets held and used, fair value | 0 | 0 | ||||||||||
Miami Fort [Member] | Fair Value, Inputs, Level 2 [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Long-lived assets held and used, fair value | 0 | 0 | ||||||||||
Miami Fort [Member] | Fair Value, Inputs, Level 3 [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Long-lived assets held and used, fair value | 36.5 | 36.5 | ||||||||||
Miami Fort [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Carrying Value | 194.2 | 194.2 | ||||||||||
Fixed-asset impairment (Note 15) | 157.7 | |||||||||||
Miami Fort [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Fair Value, Inputs, Level 3 [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Long-lived assets held and used, fair value | 36.5 | 36.5 | ||||||||||
Zimmer [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Carrying Value | 168.4 | 168.4 | ||||||||||
Fixed-asset impairment (Note 15) | 144.7 | |||||||||||
Zimmer [Member] | Fair Value, Inputs, Level 1 [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Long-lived assets held and used, fair value | 0 | 0 | ||||||||||
Zimmer [Member] | Fair Value, Inputs, Level 2 [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Long-lived assets held and used, fair value | 0 | 0 | ||||||||||
Zimmer [Member] | Fair Value, Inputs, Level 3 [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Long-lived assets held and used, fair value | 23.7 | 23.7 | ||||||||||
Zimmer [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Carrying Value | 115 | 429.9 | 115 | |||||||||
Fixed-asset impairment (Note 15) | 91.3 | 318.9 | 318.9 | |||||||||
Zimmer [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Fair Value, Inputs, Level 3 [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Long-lived assets held and used, fair value | 23.7 | 111 | 23.7 | |||||||||
Conesville [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Carrying Value | 25 | 25 | ||||||||||
Fixed-asset impairment (Note 15) | 23.9 | |||||||||||
Conesville [Member] | Fair Value, Inputs, Level 1 [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Long-lived assets held and used, fair value | 0 | 0 | ||||||||||
Conesville [Member] | Fair Value, Inputs, Level 2 [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Long-lived assets held and used, fair value | 0 | 0 | ||||||||||
Conesville [Member] | Fair Value, Inputs, Level 3 [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Long-lived assets held and used, fair value | 1.1 | 1.1 | ||||||||||
Conesville [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Carrying Value | 21.9 | 21.9 | ||||||||||
Fixed-asset impairment (Note 15) | 20.8 | |||||||||||
Conesville [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Fair Value, Inputs, Level 3 [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Long-lived assets held and used, fair value | 1.1 | 1.1 | ||||||||||
Hutchings Peakers [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Carrying Value | 3.2 | 3.2 | ||||||||||
Fixed-asset impairment (Note 15) | 1.6 | |||||||||||
Hutchings Peakers [Member] | Fair Value, Inputs, Level 1 [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Long-lived assets held and used, fair value | 0 | 0 | ||||||||||
Hutchings Peakers [Member] | Fair Value, Inputs, Level 2 [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Long-lived assets held and used, fair value | 0 | 0 | ||||||||||
Hutchings Peakers [Member] | Fair Value, Inputs, Level 3 [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Long-lived assets held and used, fair value | 1.6 | 1.6 | ||||||||||
Hutchings Peakers [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Carrying Value | 3 | 3 | ||||||||||
Fixed-asset impairment (Note 15) | 1.4 | |||||||||||
Hutchings Peakers [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Fair Value, Inputs, Level 3 [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Long-lived assets held and used, fair value | $ 1.6 | 1.6 | ||||||||||
Peaking Generating Facilities [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Carrying Value | 9.9 | |||||||||||
Fixed-asset impairment (Note 15) | 4.7 | |||||||||||
Peaking Generating Facilities [Member] | Fair Value, Inputs, Level 1 [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Long-lived assets held and used, fair value | 0 | 0 | ||||||||||
Peaking Generating Facilities [Member] | Fair Value, Inputs, Level 2 [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Long-lived assets held and used, fair value | 0 | 0 | ||||||||||
Peaking Generating Facilities [Member] | Fair Value, Inputs, Level 3 [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Long-lived assets held and used, fair value | $ 5.2 | |||||||||||
East Bend Station [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Carrying Value | 14.2 | |||||||||||
Long-lived assets held and used, fair value | 2.7 | |||||||||||
Fixed-asset impairment (Note 15) | $ 11.5 | $ 0 | 11.5 | |||||||||
East Bend Station [Member] | Fair Value, Inputs, Level 3 [Member] | ||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||
Long-lived assets held and used, fair value | $ 2.7 | |||||||||||
[1] | Goodwill impairment of $135.8 million in 2014 has been reclassified to Discontinued operations in the Consolidated Statement of Operations. |
Fair Value Measurements (Signif
Fair Value Measurements (Significant unobservalbe inputs, nonrecurring) (Details) - USD ($) $ in Millions | 3 Months Ended | ||
Dec. 31, 2016 | Jun. 30, 2016 | Dec. 31, 2014 | |
East Bend Station [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Long-lived assets held and used, fair value | $ 2.7 | ||
Income Approach Valuation Technique [Member] | Minimum [Member] | Conesville [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | (19.00%) | ||
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | (54.00%) | ||
Income Approach Valuation Technique [Member] | Minimum [Member] | Stuart [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | (12.00%) | ||
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | (61.00%) | ||
Income Approach Valuation Technique [Member] | Minimum [Member] | Killen [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | (14.00%) | (11.00%) | |
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | (57.00%) | (50.00%) | |
Income Approach Valuation Technique [Member] | Minimum [Member] | Peaking Generating Facilities [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | (22.00%) | ||
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | (29.00%) | ||
Income Approach Valuation Technique [Member] | Minimum [Member] | Hutchings Peakers [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | (20.00%) | ||
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | (40.00%) | ||
Income Approach Valuation Technique [Member] | Minimum [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Conesville [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | (19.00%) | ||
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | (54.00%) | ||
Income Approach Valuation Technique [Member] | Minimum [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Stuart [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | (12.00%) | (9.00%) | |
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | (61.00%) | (29.00%) | |
Income Approach Valuation Technique [Member] | Minimum [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Killen [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | (14.00%) | (11.00%) | |
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | (57.00%) | (50.00%) | |
Income Approach Valuation Technique [Member] | Minimum [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Zimmer [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | (14.00%) | ||
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | (46.00%) | ||
Income Approach Valuation Technique [Member] | Minimum [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Hutchings Peakers [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | (20.00%) | ||
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | (40.00%) | ||
Income Approach Valuation Technique [Member] | Maximum [Member] | Conesville [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | 11.00% | ||
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | 99.00% | ||
Income Approach Valuation Technique [Member] | Maximum [Member] | Stuart [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | 1.00% | ||
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | 75.00% | ||
Income Approach Valuation Technique [Member] | Maximum [Member] | Killen [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | 3.00% | 13.00% | |
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | 42.00% | 67.00% | |
Income Approach Valuation Technique [Member] | Maximum [Member] | Peaking Generating Facilities [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | 17.00% | ||
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | 24.00% | ||
Income Approach Valuation Technique [Member] | Maximum [Member] | Hutchings Peakers [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | 26.00% | ||
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | 63.00% | ||
Income Approach Valuation Technique [Member] | Maximum [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Conesville [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | 11.00% | ||
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | 99.00% | ||
Income Approach Valuation Technique [Member] | Maximum [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Stuart [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | 1.00% | 10.00% | |
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | 75.00% | 52.00% | |
Income Approach Valuation Technique [Member] | Maximum [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Killen [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | 3.00% | 13.00% | |
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | 42.00% | 67.00% | |
Income Approach Valuation Technique [Member] | Maximum [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Zimmer [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | 13.00% | ||
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | 80.00% | ||
Income Approach Valuation Technique [Member] | Maximum [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Hutchings Peakers [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | 26.00% | ||
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | 63.00% | ||
Income Approach Valuation Technique [Member] | Weighted Average [Member] | Conesville [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | 1.00% | ||
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | 20.00% | ||
Income Approach Valuation Technique [Member] | Weighted Average [Member] | Stuart [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | (5.00%) | ||
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | 8.00% | ||
Fair Value Inputs, Discount Rate | 10.00% | ||
Income Approach Valuation Technique [Member] | Weighted Average [Member] | Killen [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | (8.00%) | 2.00% | |
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | (16.00%) | 6.00% | |
Fair Value Inputs, Discount Rate | 10.00% | 11.00% | |
Income Approach Valuation Technique [Member] | Weighted Average [Member] | Peaking Generating Facilities [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | (3.00%) | ||
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | (4.00%) | ||
Fair Value Inputs, Discount Rate | 7.00% | ||
Income Approach Valuation Technique [Member] | Weighted Average [Member] | Hutchings Peakers [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | (1.00%) | ||
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | 12.00% | ||
Fair Value Inputs, Discount Rate | 7.00% | ||
Income Approach Valuation Technique [Member] | Weighted Average [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Conesville [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | 1.00% | ||
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | 20.00% | ||
Income Approach Valuation Technique [Member] | Weighted Average [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Stuart [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | (5.00%) | 2.00% | |
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | 8.00% | 5.00% | |
Fair Value Inputs, Discount Rate | 10.00% | 9.00% | |
Income Approach Valuation Technique [Member] | Weighted Average [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Killen [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | (8.00%) | 2.00% | |
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | (16.00%) | 6.00% | |
Fair Value Inputs, Discount Rate | 10.00% | 11.00% | |
Income Approach Valuation Technique [Member] | Weighted Average [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Zimmer [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | 1.00% | ||
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | 4.00% | ||
Fair Value Inputs, Discount Rate | 9.00% | ||
Income Approach Valuation Technique [Member] | Weighted Average [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Hutchings Peakers [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | (1.00%) | ||
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | 12.00% | ||
Fair Value Inputs, Discount Rate | 7.00% | ||
Fair Value, Inputs, Level 3 [Member] | Conesville [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Long-lived assets held and used, fair value | $ 1.1 | ||
Fair Value, Inputs, Level 3 [Member] | Miami Fort [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Long-lived assets held and used, fair value | 36.5 | ||
Fair Value, Inputs, Level 3 [Member] | Stuart [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Long-lived assets held and used, fair value | 57.4 | ||
Fair Value, Inputs, Level 3 [Member] | Killen [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Long-lived assets held and used, fair value | 42.8 | $ 84.3 | |
Fair Value, Inputs, Level 3 [Member] | Zimmer [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Long-lived assets held and used, fair value | 23.7 | ||
Fair Value, Inputs, Level 3 [Member] | East Bend Station [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Long-lived assets held and used, fair value | $ 2.7 | ||
Fair Value, Inputs, Level 3 [Member] | Peaking Generating Facilities [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Long-lived assets held and used, fair value | 5.2 | ||
Fair Value, Inputs, Level 3 [Member] | Hutchings Peakers [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Long-lived assets held and used, fair value | 1.6 | ||
Fair Value, Inputs, Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Conesville [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Long-lived assets held and used, fair value | 1.1 | ||
Fair Value, Inputs, Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Miami Fort [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Long-lived assets held and used, fair value | 36.5 | ||
Fair Value, Inputs, Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Stuart [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Long-lived assets held and used, fair value | 57.4 | 164.4 | |
Fair Value, Inputs, Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Killen [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Long-lived assets held and used, fair value | 42.8 | 84.3 | |
Fair Value, Inputs, Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Zimmer [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Long-lived assets held and used, fair value | 23.7 | $ 111 | |
Fair Value, Inputs, Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Hutchings Peakers [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Long-lived assets held and used, fair value | $ 1.6 |
Derivative Instruments and He62
Derivative Instruments and Hedging Activities (Narrative) (Details) - USD ($) | Dec. 31, 2016 | Dec. 31, 2015 |
Fair value of commodity derivative instruments | $ 29,200,000 | |
Collateral Already Posted, Aggregate Fair Value | 6,300,000 | |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 16,800,000 | |
Collateral if debt were to fall below investment grade | 6,100,000 | |
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Fair value of commodity derivative instruments | 29,200,000 | |
Collateral Already Posted, Aggregate Fair Value | 6,300,000 | |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 16,800,000 | |
Collateral if debt were to fall below investment grade | 6,100,000 | |
Tax-exempt First Mortgage Bonds - rates from: 1.29% - 1.42% (a) and 1.13% - 1.17% (b) | ||
Long-term Debt, Gross | 200,000,000 | $ 200,000,000 |
Tax-exempt First Mortgage Bonds - rates from: 1.29% - 1.42% (a) and 1.13% - 1.17% (b) | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Long-term Debt, Gross | 200,000,000 | $ 200,000,000 |
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | ||
Derivative, Notional Amount, Purchase (Sales), Net | 200,000,000 | |
Interest Rate Swap [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Designated as Hedging Instrument [Member] | ||
Derivative, Notional Amount, Purchase (Sales), Net | $ 200,000,000 |
Derivative Instruments and He63
Derivative Instruments and Hedging Activities (Outstanding Derivative Instruments) (Details) | 12 Months Ended | ||
Dec. 31, 2016USD ($)MMBTUMWh | Dec. 31, 2015USD ($)MWh | Dec. 31, 2014USD ($) | |
Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | |||
Purchase of Units Derivative Instruments Forward Power Contracts Designated as Cash Flow Hedge | MWh | 342,900 | 1,676,700 | |
Sales of Units Derivative Instruments Forward Power Contracts Designated as Cash Flow Hedge | MWh | (9,974,500) | (7,795,800) | |
Derivative, Nonmonetary Notional Amount MWh | MWh | (9,631,600) | (6,119,100) | |
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | |||
Sale of Derivative Instruments Interest Rate Swap | $ 0 | ||
Purchase of Derivative Instruments Interest Rate Swap | 200,000,000 | ||
Derivative, Notional Amount, Purchase (Sales), Net | $ 200,000,000 | ||
Designated as Hedging Instrument [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member] | |||
Purchase of Units Derivative Instruments Forward Power Contracts Designated as Cash Flow Hedge | MWh | 342,900 | 1,676,700 | |
Sales of Units Derivative Instruments Forward Power Contracts Designated as Cash Flow Hedge | MWh | (9,974,500) | (7,795,800) | |
Derivative, Nonmonetary Notional Amount MWh | MWh | (9,631,600) | (6,119,100) | |
Designated as Hedging Instrument [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Interest Rate Swap [Member] | |||
Sale of Derivative Instruments Interest Rate Swap | $ 0 | ||
Purchase of Derivative Instruments Interest Rate Swap | 200,000,000 | ||
Derivative, Notional Amount, Purchase (Sales), Net | 200,000,000 | ||
Not Designated as Hedging Instrument [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | (900,000) | $ (16,000,000) | $ (6,100,000) |
Not Designated as Hedging Instrument [Member] | Commodity Contract - FTR [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | $ (300,000) | $ 100,000 | (100,000) |
Purchase of Units Derivative Instruments Financial Transmission Rights | MWh | 2,300 | 10,200 | |
Sale of Units Derivative Instruments Financial Transmission Rights | MWh | 0 | 0 | |
Derivative, Nonmonetary Notional Amount MWh | MWh | 2,300 | 10,200 | |
Not Designated as Hedging Instrument [Member] | Commodity Contract - Heating Oil [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | $ 0 | $ 100,000 | (700,000) |
Not Designated as Hedging Instrument [Member] | Natural Gas [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | $ 2,600,000 | 0 | (200,000) |
Purchase of Units Derivative Instruments Natural Gas | MMBTU | 1,590,000 | ||
Sale of Units Derivative Instruments Natural Gas | MMBTU | 0 | ||
Derivative, Nonmonetary Notional Amount MWh | MMBTU | 1,590,000 | ||
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | $ (3,200,000) | $ (16,200,000) | (5,100,000) |
Purchase of Units Derivative Instruments Forward Power Contracts Not Designated as Hedged | MWh | 2,568,300 | 5,049,900 | |
Sales of Units Derivative Instruments Forward Power Contracts Not Designated as Hedged | MWh | (2,020,900) | (1,663,000) | |
Derivative, Nonmonetary Notional Amount MWh | MWh | 547,400 | 3,386,900 | |
Not Designated as Hedging Instrument [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | $ (1,700,000) | $ (16,000,000) | (5,500,000) |
Not Designated as Hedging Instrument [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - FTR [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | $ (300,000) | $ 100,000 | (100,000) |
Purchase of Units Derivative Instruments Financial Transmission Rights | MWh | 2,300 | 10,200 | |
Sale of Units Derivative Instruments Financial Transmission Rights | MWh | 0 | 0 | |
Derivative, Nonmonetary Notional Amount MWh | MWh | 2,300 | 10,200 | |
Not Designated as Hedging Instrument [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - Heating Oil [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | $ 0 | $ 100,000 | (700,000) |
Not Designated as Hedging Instrument [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Natural Gas [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | $ 2,600,000 | 0 | (200,000) |
Purchase of Units Derivative Instruments Natural Gas | MMBTU | 1,590,000 | ||
Sale of Units Derivative Instruments Natural Gas | MMBTU | 0 | ||
Derivative, Nonmonetary Notional Amount MWh | MMBTU | 1,590,000 | ||
Not Designated as Hedging Instrument [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | $ (4,000,000) | $ (16,200,000) | (4,500,000) |
Purchase of Units Derivative Instruments Forward Power Contracts Not Designated as Hedged | MWh | 2,568,300 | 5,049,900 | |
Sales of Units Derivative Instruments Forward Power Contracts Not Designated as Hedged | MWh | (2,037,500) | (1,665,700) | |
Derivative, Nonmonetary Notional Amount MWh | MWh | 530,800 | 3,384,200 | |
Sales [Member] | Not Designated as Hedging Instrument [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | $ (17,300,000) | $ 27,400,000 | |
Sales [Member] | Not Designated as Hedging Instrument [Member] | Commodity Contract - FTR [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | |
Sales [Member] | Not Designated as Hedging Instrument [Member] | Commodity Contract - Heating Oil [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | |
Sales [Member] | Not Designated as Hedging Instrument [Member] | Natural Gas [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | |
Sales [Member] | Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | (17,300,000) | 27,400,000 | |
Sales [Member] | Not Designated as Hedging Instrument [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | (18,100,000) | 27,400,000 | 700,000 |
Sales [Member] | Not Designated as Hedging Instrument [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - FTR [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | 0 |
Sales [Member] | Not Designated as Hedging Instrument [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - Heating Oil [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | 0 |
Sales [Member] | Not Designated as Hedging Instrument [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Natural Gas [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | 0 |
Sales [Member] | Not Designated as Hedging Instrument [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | (18,100,000) | 27,400,000 | 700,000 |
Fuel [Member] | Not Designated as Hedging Instrument [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | (600,000) | ||
Fuel [Member] | Not Designated as Hedging Instrument [Member] | Commodity Contract - FTR [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | ||
Fuel [Member] | Not Designated as Hedging Instrument [Member] | Commodity Contract - Heating Oil [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | (600,000) | ||
Fuel [Member] | Not Designated as Hedging Instrument [Member] | Natural Gas [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | ||
Fuel [Member] | Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | ||
Fuel [Member] | Not Designated as Hedging Instrument [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | (600,000) | ||
Fuel [Member] | Not Designated as Hedging Instrument [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - FTR [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | ||
Fuel [Member] | Not Designated as Hedging Instrument [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - Heating Oil [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | (600,000) | ||
Fuel [Member] | Not Designated as Hedging Instrument [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Natural Gas [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | ||
Fuel [Member] | Not Designated as Hedging Instrument [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | ||
Purchased Power [Member] | Not Designated as Hedging Instrument [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 16,400,000 | (43,500,000) | (5,400,000) |
Purchased Power [Member] | Not Designated as Hedging Instrument [Member] | Commodity Contract - FTR [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | (300,000) | 100,000 | (100,000) |
Purchased Power [Member] | Not Designated as Hedging Instrument [Member] | Commodity Contract - Heating Oil [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | 0 |
Purchased Power [Member] | Not Designated as Hedging Instrument [Member] | Natural Gas [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 2,600,000 | 0 | (200,000) |
Purchased Power [Member] | Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 14,100,000 | (43,600,000) | (5,100,000) |
Purchased Power [Member] | Not Designated as Hedging Instrument [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 16,400,000 | (43,500,000) | (5,500,000) |
Purchased Power [Member] | Not Designated as Hedging Instrument [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - FTR [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | (300,000) | 100,000 | (100,000) |
Purchased Power [Member] | Not Designated as Hedging Instrument [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - Heating Oil [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | 0 |
Purchased Power [Member] | Not Designated as Hedging Instrument [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Natural Gas [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 2,600,000 | 0 | (200,000) |
Purchased Power [Member] | Not Designated as Hedging Instrument [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | $ 14,100,000 | $ (43,600,000) | $ (5,200,000) |
Derivative Instruments and He64
Derivative Instruments and Hedging Activities (Gains or Losses Recognized in AOCI for the Cash Flow Hedges) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Forward Contract Power [Member] | |||
Beginning accumulated derivative gain / (loss) in AOCI | $ 9.2 | $ 0.2 | $ 1.4 |
Net gains / (losses) associated with current period hedging transactions | 15.7 | 18.2 | (19) |
Ending accumulated derivative gain / (loss) in AOCI | (4.3) | 9.2 | 0.2 |
Portion expected to be reclassified to earnings in the next twelve months | $ (3.5) | ||
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) | 15 months | ||
Interest Rate Contract [Member] | |||
Beginning accumulated derivative gain / (loss) in AOCI | $ 17.5 | 18.3 | 19.2 |
Net gains / (losses) associated with current period hedging transactions | 0.4 | 0 | 0 |
Ending accumulated derivative gain / (loss) in AOCI | 17.4 | 17.5 | 18.3 |
Portion expected to be reclassified to earnings in the next twelve months | $ (0.5) | ||
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) | 44 months | ||
THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member] | |||
Beginning accumulated derivative gain / (loss) in AOCI | $ 9.2 | 0.2 | 1 |
Net gains / (losses) associated with current period hedging transactions | 15.7 | 18.2 | (18.8) |
Ending accumulated derivative gain / (loss) in AOCI | (4.3) | 9.2 | 0.2 |
Portion expected to be reclassified to earnings in the next twelve months | $ (3.5) | ||
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) | 15 months | ||
THE DAYTON POWER AND LIGHT COMPANY [Member] | Interest Rate Contract [Member] | |||
Beginning accumulated derivative gain / (loss) in AOCI | $ 2 | 2.6 | 5.2 |
Net gains / (losses) associated with current period hedging transactions | 0.4 | 0 | 0 |
Ending accumulated derivative gain / (loss) in AOCI | 1.6 | 2 | 2.6 |
Portion expected to be reclassified to earnings in the next twelve months | $ (0.8) | ||
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) | 44 months | ||
Interest Expense [Member] | Forward Contract Power [Member] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | $ 0 | 0 | 0 |
Interest Expense [Member] | Interest Rate Contract [Member] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | (0.5) | (0.8) | (0.9) |
Interest Expense [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | 0 | 0 | 0 |
Interest Expense [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Interest Rate Contract [Member] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | (0.8) | (0.6) | (2.6) |
Sales [Member] | Forward Contract Power [Member] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | (35.6) | (12) | 18.3 |
Sales [Member] | Interest Rate Contract [Member] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | 0 | 0 | 0 |
Sales [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | (35.6) | (12) | 18.2 |
Sales [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Interest Rate Contract [Member] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | 0 | 0 | 0 |
Purchased Power [Member] | Forward Contract Power [Member] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | 6.4 | 2.8 | (0.5) |
Purchased Power [Member] | Interest Rate Contract [Member] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | 0 | 0 | 0 |
Purchased Power [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | 6.4 | 2.8 | (0.2) |
Purchased Power [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Interest Rate Contract [Member] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | $ 0 | $ 0 | $ 0 |
Derivative Instruments and He65
Derivative Instruments and Hedging Activities (Classification within the Condensed Consolidated Statements of Results of Operations or Balance Sheets of the Gains and Losses) (Details) - Not Designated as Hedging Instrument [Member] - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Change in unrealized gain / (loss) | $ 4.3 | $ (5.6) | $ (3) |
Realized gain / (loss) | (5.2) | (10.4) | (3.1) |
Derivative, Gain (Loss) on Derivative, Net | (0.9) | (16) | (6.1) |
Commodity Contract - Heating Oil [Member] | |||
Change in unrealized gain / (loss) | 0 | 0.4 | (0.6) |
Realized gain / (loss) | 0 | (0.3) | (0.1) |
Derivative, Gain (Loss) on Derivative, Net | 0 | 0.1 | (0.7) |
Commodity Contract - FTR [Member] | |||
Change in unrealized gain / (loss) | 0.3 | 0.3 | (0.8) |
Realized gain / (loss) | (0.6) | (0.2) | 0.7 |
Derivative, Gain (Loss) on Derivative, Net | (0.3) | 0.1 | (0.1) |
Forward Contract Power [Member] | |||
Change in unrealized gain / (loss) | 4 | (6.4) | (1.5) |
Realized gain / (loss) | (7.2) | (9.8) | (3.6) |
Derivative, Gain (Loss) on Derivative, Net | (3.2) | (16.2) | (5.1) |
Natural Gas [Member] | |||
Change in unrealized gain / (loss) | 0 | 0.1 | (0.1) |
Realized gain / (loss) | 2.6 | (0.1) | (0.1) |
Derivative, Gain (Loss) on Derivative, Net | 2.6 | 0 | (0.2) |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Change in unrealized gain / (loss) | 4.2 | (5.5) | (3) |
Realized gain / (loss) | (5.9) | (10.5) | (2.5) |
Derivative, Gain (Loss) on Derivative, Net | (1.7) | (16) | (5.5) |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - Heating Oil [Member] | |||
Change in unrealized gain / (loss) | 0 | 0.4 | (0.6) |
Realized gain / (loss) | 0 | (0.3) | (0.1) |
Derivative, Gain (Loss) on Derivative, Net | 0 | 0.1 | (0.7) |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - FTR [Member] | |||
Change in unrealized gain / (loss) | 0.3 | 0.3 | (0.8) |
Realized gain / (loss) | (0.6) | (0.2) | 0.7 |
Derivative, Gain (Loss) on Derivative, Net | (0.3) | 0.1 | (0.1) |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member] | |||
Change in unrealized gain / (loss) | 3.9 | (6.3) | (1.5) |
Realized gain / (loss) | (7.9) | (9.9) | (3) |
Derivative, Gain (Loss) on Derivative, Net | (4) | (16.2) | (4.5) |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Natural Gas [Member] | |||
Change in unrealized gain / (loss) | 0 | 0.1 | (0.1) |
Realized gain / (loss) | 2.6 | (0.1) | (0.1) |
Derivative, Gain (Loss) on Derivative, Net | 2.6 | 0 | (0.2) |
Fuel [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | (0.6) | ||
Fuel [Member] | Commodity Contract - Heating Oil [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | (0.6) | ||
Fuel [Member] | Commodity Contract - FTR [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | ||
Fuel [Member] | Forward Contract Power [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | ||
Fuel [Member] | Natural Gas [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | ||
Fuel [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | (0.6) | ||
Fuel [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - Heating Oil [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | (0.6) | ||
Fuel [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - FTR [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | ||
Fuel [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | ||
Fuel [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Natural Gas [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | ||
Purchased Power [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 16.4 | (43.5) | (5.4) |
Purchased Power [Member] | Commodity Contract - Heating Oil [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | 0 |
Purchased Power [Member] | Commodity Contract - FTR [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | (0.3) | 0.1 | (0.1) |
Purchased Power [Member] | Forward Contract Power [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 14.1 | (43.6) | (5.1) |
Purchased Power [Member] | Natural Gas [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 2.6 | 0 | (0.2) |
Purchased Power [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 16.4 | (43.5) | (5.5) |
Purchased Power [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - Heating Oil [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | 0 |
Purchased Power [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - FTR [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | (0.3) | 0.1 | (0.1) |
Purchased Power [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 14.1 | (43.6) | (5.2) |
Purchased Power [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Natural Gas [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 2.6 | 0 | (0.2) |
Regulatory Asset [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0.1 | (0.1) |
Regulatory Asset [Member] | Commodity Contract - Heating Oil [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0.1 | (0.1) |
Regulatory Asset [Member] | Commodity Contract - FTR [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | 0 |
Regulatory Asset [Member] | Forward Contract Power [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | 0 |
Regulatory Asset [Member] | Natural Gas [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | 0 |
Regulatory Asset [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0.1 | (0.1) |
Regulatory Asset [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - Heating Oil [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0.1 | (0.1) |
Regulatory Asset [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - FTR [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | 0 |
Regulatory Asset [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | 0 |
Regulatory Asset [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Natural Gas [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | $ 0 | $ 0 | $ 0 |
Derivative Instruments and He66
Derivative Instruments and Hedging Activities (Fair Value and Balance Sheet Location (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Derivative Liability, Fair Value | $ 29.2 | |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 16.8 | |
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Derivative Liability, Fair Value | 29.2 | |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 16.8 | |
Total Assets [Member] | ||
Derivative Asset, Fair Value | 20.8 | $ 30.7 |
Derivative, Collateral, Obligation to Return Securities | (16.8) | (17.9) |
Derivative, Collateral, Obligation to Return Cash | 0 | 0 |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 4 | 12.8 |
Total Assets [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Derivative Asset, Fair Value | 20.8 | 30.8 |
Derivative, Collateral, Obligation to Return Securities | (16.8) | (17.9) |
Derivative, Collateral, Obligation to Return Cash | 0 | 0 |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 4 | 12.9 |
Total Liabilities [Member] | ||
Derivative Liability, Fair Value | 29.2 | 27.5 |
Derivative, Collateral, Right to Reclaim Securities | (16.8) | (17.9) |
Derivative, Collateral, Right to Reclaim Cash | (6.3) | (8) |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 6.1 | 1.6 |
Total Liabilities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Derivative Liability, Fair Value | 29.2 | 27.5 |
Derivative, Collateral, Right to Reclaim Securities | (16.8) | (17.9) |
Derivative, Collateral, Right to Reclaim Cash | (6.3) | (8) |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 6.1 | 1.6 |
Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Prepayments and Current Assets [Member] | ||
Derivative Asset, Fair Value | 11 | 16.2 |
Derivative, Collateral, Obligation to Return Securities | (10.5) | (7.1) |
Derivative, Collateral, Obligation to Return Cash | 0 | 0 |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 0.5 | 9.1 |
Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Prepayments and Current Assets [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Derivative Asset, Fair Value | 11 | 16.2 |
Derivative, Collateral, Obligation to Return Securities | (10.5) | (7.1) |
Derivative, Collateral, Obligation to Return Cash | 0 | 0 |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 0.5 | 9.1 |
Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member] | ||
Derivative Liability, Fair Value | 16.4 | 7.1 |
Derivative, Collateral, Right to Reclaim Securities | (10.5) | (7.1) |
Derivative, Collateral, Right to Reclaim Cash | (5.5) | 0 |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 0.4 | 0 |
Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Derivative Liability, Fair Value | 16.4 | 7.1 |
Derivative, Collateral, Right to Reclaim Securities | (10.5) | (7.1) |
Derivative, Collateral, Right to Reclaim Cash | (5.5) | 0 |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 0.4 | 0 |
Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Asset [Member] | ||
Derivative Asset, Fair Value | 0.6 | 3 |
Derivative, Collateral, Obligation to Return Securities | (0.6) | (2.4) |
Derivative, Collateral, Obligation to Return Cash | 0 | 0 |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 0 | 0.6 |
Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Asset [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Derivative Asset, Fair Value | 0.6 | 3 |
Derivative, Collateral, Obligation to Return Securities | (0.6) | (2.4) |
Derivative, Collateral, Obligation to Return Cash | 0 | 0 |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 0 | 0.6 |
Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Credit [Member] | ||
Derivative Liability, Fair Value | 2.4 | 2.7 |
Derivative, Collateral, Right to Reclaim Securities | (0.6) | (2.4) |
Derivative, Collateral, Right to Reclaim Cash | (0.8) | 0 |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 1 | 0.3 |
Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Credit [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Derivative Liability, Fair Value | 2.4 | 2.7 |
Derivative, Collateral, Right to Reclaim Securities | (0.6) | (2.4) |
Derivative, Collateral, Right to Reclaim Cash | (0.8) | 0 |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 1 | 0.3 |
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member] | ||
Derivative Liability, Fair Value | 0.7 | |
Derivative, Collateral, Right to Reclaim Securities | 0 | |
Derivative, Collateral, Right to Reclaim Cash | 0 | |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 0.7 | |
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Derivative Liability, Fair Value | 0.7 | |
Derivative, Collateral, Right to Reclaim Securities | 0 | |
Derivative, Collateral, Right to Reclaim Cash | 0 | |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 0.7 | |
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Long-term Derivative Positions [Member] | Other Deferred Asset [Member] | ||
Derivative Asset, Fair Value | 1.2 | |
Derivative, Collateral, Obligation to Return Securities | 0 | |
Derivative, Collateral, Obligation to Return Cash | 0 | |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 1.2 | |
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Long-term Derivative Positions [Member] | Other Deferred Asset [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Derivative Asset, Fair Value | 1.2 | |
Derivative, Collateral, Obligation to Return Securities | 0 | |
Derivative, Collateral, Obligation to Return Cash | 0 | |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 1.2 | |
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Prepayments and Current Assets [Member] | ||
Derivative Asset, Fair Value | 6 | 7.3 |
Derivative, Collateral, Obligation to Return Securities | (4.7) | (5.5) |
Derivative, Collateral, Obligation to Return Cash | 0 | 0 |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 1.3 | 1.8 |
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Prepayments and Current Assets [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Derivative Asset, Fair Value | 6 | 7.4 |
Derivative, Collateral, Obligation to Return Securities | (4.7) | (5.5) |
Derivative, Collateral, Obligation to Return Cash | 0 | 0 |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 1.3 | 1.9 |
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member] | ||
Derivative Liability, Fair Value | 7.7 | 14.5 |
Derivative, Collateral, Right to Reclaim Securities | (4.7) | (5.5) |
Derivative, Collateral, Right to Reclaim Cash | 0 | (8) |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 3 | 1 |
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Derivative Liability, Fair Value | 7.7 | 14.5 |
Derivative, Collateral, Right to Reclaim Securities | (4.7) | (5.5) |
Derivative, Collateral, Right to Reclaim Cash | 0 | (8) |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 3 | 1 |
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Asset [Member] | ||
Derivative Asset, Fair Value | 1.9 | 4 |
Derivative, Collateral, Obligation to Return Securities | (1) | (2.7) |
Derivative, Collateral, Obligation to Return Cash | 0 | 0 |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 0.9 | 1.3 |
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Asset [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Derivative Asset, Fair Value | 1.9 | 4 |
Derivative, Collateral, Obligation to Return Securities | (1) | (2.7) |
Derivative, Collateral, Obligation to Return Cash | 0 | 0 |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 0.9 | 1.3 |
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Credit [Member] | ||
Derivative Liability, Fair Value | 2 | 2.7 |
Derivative, Collateral, Right to Reclaim Securities | (1) | (2.7) |
Derivative, Collateral, Right to Reclaim Cash | 0 | 0 |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 1 | 0 |
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Credit [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Derivative Liability, Fair Value | 2 | 2.7 |
Derivative, Collateral, Right to Reclaim Securities | (1) | (2.7) |
Derivative, Collateral, Right to Reclaim Cash | 0 | 0 |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 1 | 0 |
Not Designated as Hedging Instrument [Member] | Commodity Contract - FTR [Member] | Short-term Derivative Positions [Member] | Other Prepayments and Current Assets [Member] | ||
Derivative Asset, Fair Value | 0.1 | 0.2 |
Derivative, Collateral, Obligation to Return Securities | 0 | (0.2) |
Derivative, Collateral, Obligation to Return Cash | 0 | 0 |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 0.1 | 0 |
Not Designated as Hedging Instrument [Member] | Commodity Contract - FTR [Member] | Short-term Derivative Positions [Member] | Other Prepayments and Current Assets [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Derivative Asset, Fair Value | 0.1 | 0.2 |
Derivative, Collateral, Obligation to Return Securities | 0 | (0.2) |
Derivative, Collateral, Obligation to Return Cash | 0 | 0 |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 0.1 | 0 |
Not Designated as Hedging Instrument [Member] | Commodity Contract - FTR [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member] | ||
Derivative Liability, Fair Value | 0 | 0.5 |
Derivative, Collateral, Right to Reclaim Securities | 0 | (0.2) |
Derivative, Collateral, Right to Reclaim Cash | 0 | 0 |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 0 | 0.3 |
Not Designated as Hedging Instrument [Member] | Commodity Contract - FTR [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Derivative Liability, Fair Value | 0 | 0.5 |
Derivative, Collateral, Right to Reclaim Securities | 0 | (0.2) |
Derivative, Collateral, Right to Reclaim Cash | 0 | 0 |
Derivative Liability, Fair Value, Amount Offset Against Collateral | $ 0 | $ 0.3 |
Goodwill And Other Intangible67
Goodwill And Other Intangible Assets (Change In Goodwill) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||||||
Dec. 31, 2015 | Mar. 31, 2015 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | ||
Goodwill [Line Items] | ||||||||||
Goodwill impairment | [1] | $ 0 | $ (317) | $ (135.8) | ||||||
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||||||
Goodwill [Line Items] | ||||||||||
Goodwill | $ 2,440.5 | 2,440.5 | 2,440.5 | |||||||
Accumulated impairment losses | (2,440.5) | (2,440.5) | (2,123.5) | |||||||
Goodwill, net balance | 0 | 0 | $ 317 | $ 317 | ||||||
Goodwill impairment | $ (317) | $ (317) | $ (317) | |||||||
DPLER [Member] | ||||||||||
Goodwill [Line Items] | ||||||||||
Goodwill, net balance | $ 135.8 | $ 135.8 | ||||||||
Goodwill impairment | $ (135.8) | $ (135.8) | ||||||||
[1] | Goodwill impairment of $135.8 million in 2014 has been reclassified to Discontinued operations in the Consolidated Statement of Operations. |
Goodwill And Other Intangible68
Goodwill And Other Intangible Asset (Narrative) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||||||
Dec. 31, 2015 | Mar. 31, 2015 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | ||
Goodwill [Line Items] | ||||||||||
Goodwill Allocated to DP&L Reporting Unit | $ 2.4 | |||||||||
Goodwill, Impairment Loss | [1] | $ 0 | $ 317 | $ 135.8 | ||||||
DPLER [Member] | ||||||||||
Goodwill [Line Items] | ||||||||||
Goodwill | $ 135.8 | $ 135.8 | ||||||||
Goodwill, Impairment Loss | $ 135.8 | $ 135.8 | ||||||||
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||||||
Goodwill [Line Items] | ||||||||||
Goodwill | $ 0 | 0 | $ 317 | $ 317 | ||||||
Goodwill, Impairment Loss | $ 317 | $ 317 | $ 317 | |||||||
[1] | Goodwill impairment of $135.8 million in 2014 has been reclassified to Discontinued operations in the Consolidated Statement of Operations. |
Debt (Narrative) (Details)
Debt (Narrative) (Details) | Jul. 01, 2017 | Feb. 21, 2017 | Oct. 17, 2016USD ($) | Feb. 05, 2016USD ($) | Aug. 03, 2015USD ($) | Jul. 01, 2015USD ($) | Mar. 31, 2014USD ($) | Oct. 31, 2014USD ($) | Jun. 30, 2015USD ($) | Jun. 30, 2018USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($)letter_of_creditfiscal_quarterdebt_covenant | Mar. 31, 2017 | Jan. 06, 2016USD ($) | Dec. 31, 2015USD ($) | Sep. 30, 2015fiscal_quarter | Jul. 31, 2015USD ($) |
Debt Instrument [Line Items] | |||||||||||||||||
Current portion - long-term debt | $ 29,700,000 | $ 572,800,000 | |||||||||||||||
Debt Covenant, Leverage Ratio, Maximum | 0.67 | ||||||||||||||||
Debt Covenant, Interest Coverage Ratio, Minimum | 2.50 | ||||||||||||||||
Leverage Ratio | 1.45 | ||||||||||||||||
Debt Covenant, Total Debt to Total Capitalization Ratio, Maximum | 0.65 | ||||||||||||||||
Total Debt to Total Capitalization Ratio | 0.68 | ||||||||||||||||
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Number of Letters of Credit | 2 | ||||||||||||||||
Current portion - long-term debt | $ 4,700,000 | 443,100,000 | |||||||||||||||
Notes payable - related party | $ 15,000,000 | ||||||||||||||||
Debt Covenant, Total Debt to Total Capitalization Ratio, Maximum | 0.65 | ||||||||||||||||
Total Debt to Total Capitalization Ratio | 0.68 | ||||||||||||||||
Revolving Credit Agreeement with Bank Group Expiring 2018 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Unsecured revolving credit agreement | $ 300,000,000 | ||||||||||||||||
Debt Instrument, Term | 5 years | ||||||||||||||||
Letter of credit sublimit | $ 100,000,000 | ||||||||||||||||
Line of credit facility, additional borrowing capacity | 100,000,000 | ||||||||||||||||
Letters of credit outstanding | $ 35,300,000 | $ 1,400,000 | |||||||||||||||
Line of credit facility, remaining borrowing capacity | $ 173,600,000 | ||||||||||||||||
Revolving Credit Agreement with Bank Group Expiring 2020 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Unsecured revolving credit agreement | $ 175,000,000 | ||||||||||||||||
Letter of credit sublimit | 50,000,000 | ||||||||||||||||
Line of credit facility, additional borrowing capacity | 100,000,000 | ||||||||||||||||
Revolving Credit Agreement and Standby Letters of Credit [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Number of financial covenants | debt_covenant | 2 | ||||||||||||||||
Number of prior quarters included in debt to EBITDA ratio | fiscal_quarter | 4 | 4 | |||||||||||||||
U.S. Government note maturing in 2061 - 4.20% [Member] | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Debt Instrument, Maturity Date Range, End | Feb. 1, 2061 | ||||||||||||||||
Long-term Debt, Gross | $ 18,000,000 | 18,100,000 | |||||||||||||||
Debt instrument interest percentage | 4.20% | ||||||||||||||||
U.S. Government note maturing in 2061 - 4.20% [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Debt Instrument, Maturity Date Range, End | Feb. 1, 2061 | ||||||||||||||||
Long-term Debt, Gross | $ 18,000,000 | 18,100,000 | |||||||||||||||
Debt instrument interest percentage | 4.20% | ||||||||||||||||
First Mortgage Bonds Maturing in 2016 - 1.875% | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Debt Instrument, Maturity Date Range, End | Sep. 1, 2016 | ||||||||||||||||
Long-term Debt, Gross | $ 0 | $ 445,000,000 | |||||||||||||||
Debt instrument interest percentage | 1.875% | 1.875% | |||||||||||||||
First Mortgage Bonds Maturing in 2016 - 1.875% | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Debt Instrument, Maturity Date Range, End | Sep. 1, 2016 | ||||||||||||||||
Long-term Debt, Gross | $ 0 | $ 445,000,000 | |||||||||||||||
Debt instrument interest percentage | 1.875% | 1.875% | |||||||||||||||
Term Loan Maturing 2022 [Member] | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Long-term Debt, Gross | $ 445,000,000 | ||||||||||||||||
Basis spread on variable interest rate (percent) | 3.25% | ||||||||||||||||
Debt Instrument, Interest Rate, Effective Percentage Rate Range, Minimum LIBOR | 0.75% | ||||||||||||||||
Term Loan Maturing 2022 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Long-term Debt, Gross | $ 445,000,000 | ||||||||||||||||
Basis spread on variable interest rate (percent) | 3.25% | ||||||||||||||||
Debt Instrument, Interest Rate, Effective Percentage Rate Range, Minimum LIBOR | 0.75% | ||||||||||||||||
Bank Term Loan maturing in May 2018 [Member] | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Debt Instrument, Maturity Date Range, End | Jul. 31, 2020 | ||||||||||||||||
Long-term Debt, Gross | $ 125,000,000 | $ 125,000,000 | 160,000,000 | ||||||||||||||
Bank Term Loan Maturing July 2020 [Member] | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Long-term Debt, Gross | 125,000,000 | ||||||||||||||||
DPL Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Unsecured revolving credit agreement | $ 100,000,000 | 205,000,000 | |||||||||||||||
Debt Instrument, Term | 5 years | ||||||||||||||||
Number of letters of credit outstanding | letter_of_credit | 2 | ||||||||||||||||
Letter of credit sublimit | $ 100,000,000 | 200,000,000 | |||||||||||||||
Line of credit facility, additional borrowing capacity | $ 50,000,000 | $ 95,000,000 | |||||||||||||||
Letters of credit outstanding | $ 1,700,000 | ||||||||||||||||
Line of credit facility, remaining borrowing capacity | $ 203,300,000 | ||||||||||||||||
DPL Revolving Credit Agreement and Term Loan Maturing July 2020 [Member] | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Number of financial covenants | debt_covenant | 2 | ||||||||||||||||
Debt Instrument, Debt Covenant, Debt to EBITDA Ratio, Number of Quarters | fiscal_quarter | 4 | ||||||||||||||||
Number of prior quarters included in debt to EBITDA ratio | fiscal_quarter | 4 | ||||||||||||||||
Senior Unsecured Bonds at 6.50% maturing in 2016 [Member] | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Debt Instrument, Maturity Date Range, End | Oct. 1, 2016 | ||||||||||||||||
Long-term Debt, Gross | $ 130,000,000 | $ 0 | $ 130,000,000 | 130,000,000 | |||||||||||||
Make Whole Premium | $ 2,400,000 | ||||||||||||||||
Extinguishment of debt, amount | $ 57,000,000 | $ 73,000,000 | $ 300,000,000 | ||||||||||||||
Debt instrument interest percentage | 6.50% | 6.50% | 6.50% | ||||||||||||||
Senior Unsecured Bonds at 7.25% maturing in 2021 [Member] | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Debt Instrument, Maturity Date Range, End | Oct. 1, 2021 | ||||||||||||||||
Long-term Debt, Gross | $ 780,000,000 | 780,000,000 | |||||||||||||||
Debt instrument interest percentage | 7.25% | ||||||||||||||||
Senior Unsecured notes maturing October 2019 at 6.75% [Member] | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Debt Instrument, Face Amount | $ 200,000,000 | ||||||||||||||||
Debt instrument interest percentage | 6.75% | ||||||||||||||||
Note to DPL Capital Trust II Maturing in 2031 - 8.125% [Member] | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Debt Instrument, Maturity Date Range, End | Sep. 1, 2031 | ||||||||||||||||
Long-term Debt, Gross | $ 15,600,000 | $ 15,600,000 | |||||||||||||||
Repayments of debt | $ 5,000,000 | ||||||||||||||||
Debt instrument interest percentage | 8.125% | ||||||||||||||||
Pollution control series maturing in November 2040 - variable rates: 0.04% - 0.26% and 0.06% - 0.32% [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Extinguishment of debt, amount | $ 100,000,000 | ||||||||||||||||
Pollution Control Series Maturing in 2028 - 4.70% [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Extinguishment of debt, amount | $ 35,300,000 | ||||||||||||||||
Debt instrument interest percentage | 4.70% | ||||||||||||||||
Pollution Control Series Maturing in 2034 - 4.80% [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Extinguishment of debt, amount | 137,800,000 | $ 41,300,000 | |||||||||||||||
Repayments of debt | $ 37,800,000 | ||||||||||||||||
Debt instrument interest percentage | 4.80% | 4.80% | |||||||||||||||
Note Payable to DPL Inc. [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Debt instrument interest percentage | 3.02% | 2.67% | |||||||||||||||
Notes payable - related party | $ 5,000,000 | $ 35,000,000 | |||||||||||||||
Variable Rate Notes Backed by Term Loan and First Mortgage Bonds [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Debt Instrument, Face Amount | $ 200,000,000 | ||||||||||||||||
London Interbank Offered Rate (LIBOR) [Member] | Note Payable to DPL Inc. [Member] | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Basis spread on variable interest rate (percent) | 2.00% | ||||||||||||||||
Subsequent Event [Member] | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Debt Covenant, Total Debt to Total Capitalization Ratio, Maximum | 0.75 | ||||||||||||||||
Long Term Indebtedness, Less than or Equal to | $ 750,000,000 | $ 750,000,000 | |||||||||||||||
Total Debt to Total Capitalization Ratio | 0.53 | ||||||||||||||||
Subsequent Event [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Debt Covenant, Total Debt to Total Capitalization Ratio, Maximum | 0.75 | ||||||||||||||||
Long Term Indebtedness, Less than or Equal to | $ 750,000,000 | $ 750,000,000 | |||||||||||||||
Total Debt to Total Capitalization Ratio | 0.53 | ||||||||||||||||
Subsequent Event [Member] | Term Loan Maturing 2022 [Member] | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Quarterly Loan Amortization of Initial Principal Balance | 0.25% | ||||||||||||||||
Subsequent Event [Member] | Term Loan Maturing 2022 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Quarterly Loan Amortization of Initial Principal Balance | 0.25% |
Debt (Long-term Debt) (Details)
Debt (Long-term Debt) (Details) - USD ($) $ in Millions | 12 Months Ended | ||||||
Dec. 31, 2016 | Dec. 31, 2015 | Jan. 06, 2016 | Aug. 03, 2015 | Jul. 31, 2015 | Jul. 01, 2015 | Oct. 31, 2014 | |
Debt Instrument [Line Items] | |||||||
Capital Lease Obligations | $ 0.4 | $ 0 | |||||
Unamortized Deferred Financing Costs | (8.8) | (11.1) | |||||
Debt Instrument, Unamortized Discount (Premium), Net | (0.6) | (0.7) | |||||
Total long-term debt at subsidary | 747.2 | 754.5 | |||||
Less: current portion | (29.7) | (572.8) | |||||
Total | $ 1,828.7 | 1,420.5 | |||||
Debt maturity date, earliest | 2,019 | ||||||
Debt maturity date, latest | 2,061 | ||||||
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Capital Lease Obligations | $ 0.4 | 0 | |||||
Unamortized Deferred Financing Costs | (11.8) | (6.2) | |||||
Unamortized Deferred Financing Costs (Subsidiary) | (10.7) | (5) | |||||
Debt Instrument, Unamortized Discount | (2.2) | (0.2) | |||||
Debt Instrument, Unamortized Discount (Premium), Net | (5.5) | (3.6) | |||||
Less: current portion | (4.7) | (443.1) | |||||
Total | 744.7 | 313.6 | |||||
Term Loan Maturing 2022 (DPL) [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt, Gross | $ 445 | $ 0 | |||||
Debt instrument maturity year | Aug. 24, 2022 | ||||||
Debt Instrument, Interest Rate, Effective Percentage Rate Range, Minimum | 4.00% | 0.00% | |||||
Debt Instrument, Interest Rate, Effective Percentage Rate Range, Maximum | 4.01% | 0.00% | |||||
Term Loan Maturing 2022 (DPL) [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt, Gross | $ 445 | $ 0 | |||||
Debt instrument maturity year | Aug. 24, 2022 | ||||||
Debt Instrument, Interest Rate, Effective Percentage Rate Range, Minimum | 4.00% | 0.00% | |||||
Debt Instrument, Interest Rate, Effective Percentage Rate Range, Maximum | 4.01% | 0.00% | |||||
First Mortgage Bonds Maturing in 2016 - 1.875% | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt, Gross | $ 0 | $ 445 | |||||
Debt instrument maturity year | Sep. 1, 2016 | ||||||
Debt instrument interest percentage | 1.875% | 1.875% | |||||
First Mortgage Bonds Maturing in 2016 - 1.875% | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt, Gross | $ 0 | $ 445 | |||||
Debt instrument maturity year | Sep. 1, 2016 | ||||||
Debt instrument interest percentage | 1.875% | 1.875% | |||||
Pollution Control Series Maturing in 2028 - 4.70% [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt instrument interest percentage | 4.70% | ||||||
Pollution Control Series Maturing in 2034 - 4.80% [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt instrument interest percentage | 4.80% | 4.80% | |||||
Pollution Control Series Maturing in 2036 - 4.80% [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt, Gross | $ 100 | $ 100 | |||||
Debt instrument maturity year | Sep. 1, 2036 | ||||||
Debt instrument interest percentage | 4.80% | ||||||
Pollution Control Series Maturing in 2036 - 4.80% [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt, Gross | $ 100 | 100 | |||||
Debt instrument maturity year | Sep. 1, 2036 | ||||||
Debt instrument interest percentage | 4.80% | ||||||
Tax-exempt First Mortgage Bonds - rates from: 1.29% - 1.42% (a) and 1.13% - 1.17% (b) | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt, Gross | $ 200 | $ 200 | |||||
Debt instrument maturity year | Aug. 1, 2020 | ||||||
Debt instrument interest percentage minimum | 1.29% | 1.13% | |||||
Debt instrument interest percentage maximum | 1.42% | 1.17% | |||||
Tax-exempt First Mortgage Bonds - rates from: 1.29% - 1.42% (a) and 1.13% - 1.17% (b) | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt, Gross | $ 200 | $ 200 | |||||
Debt instrument maturity year | Aug. 1, 2020 | ||||||
Debt instrument interest percentage minimum | 1.29% | ||||||
Debt instrument interest percentage maximum | 1.42% | ||||||
U.S. Government note maturing in 2061 - 4.20% [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt, Gross | $ 18 | 18.1 | |||||
Debt instrument maturity year | Feb. 1, 2061 | ||||||
Debt instrument interest percentage | 4.20% | ||||||
U.S. Government note maturing in 2061 - 4.20% [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt, Gross | $ 18 | 18.1 | |||||
Debt instrument maturity year | Feb. 1, 2061 | ||||||
Debt instrument interest percentage | 4.20% | ||||||
Bank Term Loan maturing in May 2018 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt, Gross | $ 125 | $ 125 | $ 160 | ||||
Debt instrument maturity year | Jul. 31, 2020 | ||||||
Debt instrument interest percentage minimum | 2.67% | 2.44% | |||||
Debt instrument interest percentage maximum | 3.02% | 2.67% | |||||
Senior Unsecured Bonds at 6.50% maturing in 2016 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt, Gross | $ 0 | $ 130 | $ 130 | $ 130 | |||
Debt instrument maturity year | Oct. 1, 2016 | ||||||
Debt instrument interest percentage | 6.50% | 6.50% | 6.50% | ||||
Senior Unsecured Bonds at 6.75% maturing in 2019 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt, Gross | $ 200 | 200 | |||||
Debt instrument maturity year | Oct. 1, 2019 | ||||||
Debt instrument interest percentage | 6.75% | ||||||
Senior Unsecured Bonds at 7.25% maturing in 2021 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt, Gross | $ 780 | 780 | |||||
Debt instrument maturity year | Oct. 1, 2021 | ||||||
Debt instrument interest percentage | 7.25% | ||||||
Note to DPL Capital Trust II Maturing in 2031 - 8.125% [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt, Gross | $ 15.6 | $ 15.6 | |||||
Debt instrument maturity year | Sep. 1, 2031 | ||||||
Debt instrument interest percentage | 8.125% |
Debt (Long-term Debt Maturities
Debt (Long-term Debt Maturities) (Details) $ in Millions | Dec. 31, 2016USD ($) |
Debt Instrument [Line Items] | |
2,016 | $ 29.7 |
2,017 | 29.6 |
2,018 | 229.6 |
2,019 | 254.6 |
2,020 | 784.6 |
Thereafter | 555.5 |
Total Maturities | 1,883.6 |
Unamortized discounts and premiums, net | (6.1) |
Total long-term debt | 1,877.5 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Debt Instrument [Line Items] | |
2,016 | 4.7 |
2,017 | 4.6 |
2,018 | 4.6 |
2,019 | 204.6 |
2,020 | 4.5 |
Thereafter | 540 |
Total Maturities | 763 |
Unamortized discounts and premiums, net | (2.2) |
Total long-term debt | $ 760.8 |
Income Taxes (Components of Inc
Income Taxes (Components of Income Tax Expense) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Income Taxes [Line Items] | |||
Estimated Annual Effective Income Tax Rate, Continuing Operations | 35.00% | ||
Federal income tax | $ (277.6) | $ (81) | $ 25.4 |
State income taxes, net of federal effect | (1) | (0.1) | 0.8 |
Depreciation of AFUDC - Equity | 2.7 | (3.5) | (3.4) |
Investment tax credit amortized | (0.4) | (0.5) | (0.5) |
Section 199 - domestic production deduction | (4.5) | (4.1) | (1.1) |
Non-deductible goodwill impairment | 0 | 111 | 0 |
Accrual (settlement) for open tax years | 2.2 | 0 | (6.6) |
Other, net | (0.2) | (1.8) | 0.8 |
Total tax expense | (278.8) | 20 | 15.4 |
Federal - Current | 14.7 | 30.1 | (5.2) |
State and Local - Current | 0.6 | 0.8 | 0.4 |
Total Current | 15.3 | 30.9 | (4.8) |
Federal - Deferred | (290.2) | (9.9) | 19.6 |
State and Local - Deferred | (3.9) | (1) | 0.6 |
Total Deferred | (294.1) | (10.9) | 20.2 |
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense | $ (0.3) | 0.2 | 0.4 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Income Taxes [Line Items] | |||
Estimated Annual Effective Income Tax Rate, Continuing Operations | 35.00% | ||
Federal income tax | $ (418.5) | 49.3 | 53.8 |
State income taxes, net of federal effect | (5) | 0.4 | 1.2 |
Depreciation of AFUDC - Equity | 3.3 | (2.8) | (2.7) |
Investment tax credit amortized | (2.3) | (2.4) | (2.5) |
Section 199 - domestic production deduction | (5.3) | (6.1) | (4.6) |
Accrual (settlement) for open tax years | 3.4 | 0 | (6.6) |
Other, net | 2 | (3.3) | 1.1 |
Total tax expense | (422.4) | 35.1 | 39.7 |
Federal - Current | 51.6 | 55.8 | 34.1 |
State and Local - Current | 0.6 | 0.8 | 0.5 |
Total Current | 52.2 | 56.6 | 34.6 |
Federal - Deferred | (466.3) | (21) | 4.1 |
State and Local - Deferred | (8.3) | (0.5) | 1 |
Total Deferred | (474.6) | (21.5) | 5.1 |
Increase (Decrease) in Income Taxes | $ (2.9) | $ 0.4 | $ (0.7) |
Income Taxes (Effective and Sta
Income Taxes (Effective and Statutory Rate Reconciliation) (Details) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Entity Information [Line Items] | |||
Statutory Federal tax rate | 35.00% | 35.00% | 35.00% |
State taxes, net of Federal tax benefit | 0.10% | 0.10% | 1.10% |
AFUDC - Equity | (0.30%) | 1.50% | (4.70%) |
Amortization of investment tax credits | 0.00% | 0.20% | (0.70%) |
Section 199 - domestic production deduction | 0.60% | 1.80% | (1.60%) |
Non-deductible goodwill impairment | 0.00% | (48.00%) | 0.00% |
Other, net | (0.30%) | 0.80% | (7.90%) |
Effective tax rate | 35.10% | (8.60%) | 21.20% |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Entity Information [Line Items] | |||
Statutory Federal tax rate | 35.00% | 35.00% | 35.00% |
State taxes, net of Federal tax benefit | 0.40% | 0.30% | 0.80% |
AFUDC - Equity | (0.30%) | (2.00%) | (1.70%) |
Amortization of investment tax credits | 0.20% | (1.70%) | (1.60%) |
Section 199 - domestic production deduction | 0.40% | (4.30%) | (3.00%) |
Other, net | (0.40%) | (2.50%) | (3.80%) |
Effective tax rate | 35.30% | 24.80% | 25.70% |
Income Taxes (Components of Def
Income Taxes (Components of Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Income Taxes [Line Items] | |||
Depreciation / property basis | $ (255.3) | $ (539.8) | |
Income taxes recoverable | (11.9) | (12) | |
Regulatory assets | (7.8) | (10.6) | |
Investment tax credit | 0.5 | 0.7 | |
Compensation and employee benefits | 5.5 | 3.1 | |
Intangibles | (1.5) | (8.4) | |
Long-term debt | (0.7) | (1.1) | |
Other | 18.8 | (0.6) | |
Net non-current liabilities | $ (252.4) | (568.7) | |
Estimated Annual Effective Income Tax Rate, Continuing Operations | 35.00% | ||
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense | $ (0.3) | 0.2 | $ 0.4 |
Deferred tax assets related to state and local tax net operating loss carryforwards, net of related valuation allowances | 24.9 | 26 | |
Deferred tax assets related to state and local net operating loss carryforwards, valuation allowances | 3.3 | 17.2 | |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Income Taxes [Line Items] | |||
Depreciation / property basis | (129.8) | (608.8) | |
Income taxes recoverable | (11.9) | (12) | |
Regulatory assets | (9.1) | (11.5) | |
Investment tax credit | 6.3 | 7 | |
Compensation and employee benefits | 1.1 | 3.6 | |
Other | (2.9) | (9.5) | |
Net non-current liabilities | $ (146.3) | (631.2) | |
Estimated Annual Effective Income Tax Rate, Continuing Operations | 35.00% | ||
Increase (Decrease) in Income Taxes | $ (2.9) | $ 0.4 | $ (0.7) |
Income Taxes (Tax or Benefit cr
Income Taxes (Tax or Benefit credited to AOCI) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Income Taxes [Line Items] | |||
Tax expense/ (benefit) | $ (9.6) | $ 6.3 | $ (9.1) |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Income Taxes [Line Items] | |||
Tax expense/ (benefit) | $ (7) | $ 7.5 | $ (6) |
Income Taxes (Reconciliation of
Income Taxes (Reconciliation of Unrecognized Tax Benefits) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | ||
Balance at beginning of year | $ 3 | $ 3 |
Tax positions taken during prior periods | 2.2 | 0 |
Lapse of applicable statute of limitations | (1.5) | 0 |
Balance at end of year | 3.7 | 3 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | ||
Balance at beginning of year | 3 | 3 |
Tax positions taken during prior periods | 3.4 | 0 |
Lapse of applicable statute of limitations | (1.5) | 0 |
Balance at end of year | $ 4.9 | $ 3 |
Income Taxes (Narrative) (Detai
Income Taxes (Narrative) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Income Taxes [Line Items] | |
Unrecognized tax benefits due to uncertainty in timing of deductibility | $ 0.9 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Income Taxes [Line Items] | |
Unrecognized tax benefits due to uncertainty in timing of deductibility | $ 0.9 |
Benefit Plans (Narrative) (Deta
Benefit Plans (Narrative) (Details) - USD ($) | Jan. 31, 2017 | Jan. 31, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined Benefit Plan, Amount Billed to Service Company | $ 1,300,000 | $ 2,200,000 | ||||
Defined contribution plan, maximum annual contributions per employee (percent) | 85.00% | |||||
Employer contributions to defined contribution plan | $ 4,900,000 | 4,800,000 | $ 4,700,000 | |||
Accumulated benefit obligation for our defined benefit pension plans | 409,200,000 | 401,200,000 | ||||
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined Benefit Plan, Amount Billed to Service Company | $ 1,300,000 | 2,200,000 | ||||
Defined contribution plan, maximum annual contributions per employee (percent) | 85.00% | |||||
Employer contributions to defined contribution plan | $ 4,900,000 | 4,800,000 | 4,700,000 | |||
Accumulated benefit obligation for our defined benefit pension plans | $ 409,200,000 | 401,200,000 | ||||
Defined Benefit Plan [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined benefit plan employee vested percentage | 100.00% | |||||
Defined benefit plan employee vested minimum period, years | 5 years | |||||
Defined benefit plan, percent forfeited if terminated, other than by death or disability, prior to full vesting (percent) | 100.00% | |||||
Defined Benefit Plan [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined benefit plan employee vested percentage | 100.00% | |||||
Defined benefit plan employee vested minimum period, years | 5 years | |||||
Defined benefit plan, percent forfeited if terminated, other than by death or disability, prior to full vesting (percent) | 100.00% | |||||
Cash Balance Plan [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined benefit plan employee vested percentage | 100.00% | |||||
Defined benefit plan employee vested minimum period, years | 3 years | |||||
Defined benefit plan, percent forfeited if terminated, other than by death or disability, prior to full vesting (percent) | 100.00% | |||||
Management Employees [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined benefit plan employee vested percentage | 100.00% | |||||
Defined benefit plan employee vested minimum period, years | 3 years | |||||
Defined benefit plan, percent forfeited if terminated, other than by death or disability, prior to full vesting (percent) | 100.00% | |||||
Pension [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Pension Contributions | $ 5,000,000 | $ 5,000,000 | $ 0 | |||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets | 6.50% | 6.50% | 6.75% | |||
Discount rate for obligations | 4.28% | 4.49% | 4.02% | |||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 4.49% | 4.02% | 4.86% | |||
Defined Benefit Plan, Fair Value of Plan Assets | $ 341,000,000 | $ 345,400,000 | $ 371,700,000 | |||
Service cost | 5,700,000 | 7,100,000 | 5,900,000 | |||
Interest cost | 14,700,000 | 17,300,000 | 17,500,000 | |||
Defined Benefit Plan, Funded Status of Plan | $ (78,600,000) | (65,400,000) | ||||
Defined benefit plan, amortization period for underfunding excess | 7 years | |||||
Pension [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Pension Contributions | $ 5,000,000 | $ 5,000,000 | $ 0 | |||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets | 6.50% | 6.50% | 6.75% | |||
Discount rate for obligations | 4.28% | 4.49% | 4.02% | |||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 4.49% | 4.02% | 4.86% | |||
Defined Benefit Plan, Fair Value of Plan Assets | $ 341,000,000 | $ 345,400,000 | $ 371,700,000 | |||
Service cost | 5,700,000 | 7,100,000 | 5,900,000 | |||
Interest cost | 14,700,000 | 17,300,000 | $ 17,500,000 | |||
Defined Benefit Plan, Funded Status of Plan | $ (78,600,000) | (65,400,000) | ||||
Defined benefit plan, amortization period for underfunding excess | 7 years | |||||
Postretirement [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined Benefit Plan, Funded Status of Plan | $ 15,800,000 | 15,000,000 | ||||
Postretirement [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined Benefit Plan, Funded Status of Plan | 15,800,000 | $ 15,000,000 | ||||
SERP [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Estimated contribution to the defined benefit plans next year | $ 400,000 | |||||
Equity Securities [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Target allocations for plan assets, fixed income securities, minimum | 28.00% | |||||
Target allocations for plan assets, fixed income securities, maximum | 48.00% | |||||
Equity Securities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Target allocations for plan assets, fixed income securities, minimum | 28.00% | |||||
Target allocations for plan assets, fixed income securities, maximum | 48.00% | |||||
Fixed Income Securities [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Target allocations for plan assets, fixed income securities, minimum | 42.00% | |||||
Target allocations for plan assets, fixed income securities, maximum | 70.00% | |||||
Fixed Income Securities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Target allocations for plan assets, fixed income securities, minimum | 42.00% | |||||
Target allocations for plan assets, fixed income securities, maximum | 70.00% | |||||
Scenario, Forecast [Member] | Pension [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Service cost | $ 5,700,000 | |||||
Defined Benefit Plan, Administration Expenses | 600,000 | |||||
Scenario, Forecast [Member] | Pension [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Service cost | 5,700,000 | |||||
Defined Benefit Plan, Administration Expenses | 600,000 | |||||
Increase in Expected Rate of Return [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Change in Expected rate of return on plan assets | 1.00% | |||||
Change in Pension Expense | $ (3,500,000) | |||||
Increase in Expected Rate of Return [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Change in Expected rate of return on plan assets | 1.00% | |||||
Change in Pension Expense | $ (3,500,000) | |||||
Decrease in Expected Rate of Return [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Change in Pension Expense | $ 3,500,000 | |||||
Decrease in Expected Rate of Return [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Change in Expected rate of return on plan assets | 1.00% | |||||
Change in Pension Expense | $ 3,500,000 | |||||
Expected Increase in Discount Rate [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Change in Pension Expense | (300,000) | |||||
Expected Increase in Discount Rate [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Change in Pension Expense | $ (300,000) | |||||
Change in Discount Rate | 0.25% | |||||
Expected Decrease in Discount Rate [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Change in Pension Expense | $ 400,000 | |||||
Expected Decrease in Discount Rate [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Change in Pension Expense | $ 400,000 | |||||
Change in Discount Rate | 0.25% | |||||
Non-union Participant [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined contribution plan, period after which participant is fully vested in employer contributions | 2 years | |||||
Non-union Participant [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined contribution plan, period after which participant is fully vested in employer contributions | 2 years | |||||
Non-union Participant [Member] | First 1% of Eligible Compensation [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined contribution plan, employer matching contribution (percent) | 100.00% | |||||
Defined contribution plan, employer matching contribution, percent of employees' gross pay (percent) | 1.00% | |||||
Non-union Participant [Member] | First 1% of Eligible Compensation [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined contribution plan, employer matching contribution (percent) | 100.00% | |||||
Defined contribution plan, employer matching contribution, percent of employees' gross pay (percent) | 1.00% | |||||
Non-union Participant [Member] | Next 5% of Eligible Compensation [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined contribution plan, employer matching contribution (percent) | 50.00% | |||||
Defined contribution plan, employer matching contribution, percent of employees' gross pay (percent) | 5.00% | |||||
Non-union Participant [Member] | Next 5% of Eligible Compensation [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined contribution plan, employer matching contribution (percent) | 50.00% | |||||
Defined contribution plan, employer matching contribution, percent of employees' gross pay (percent) | 5.00% | |||||
Union Participant [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined contribution plan, employer matching contribution, percent of employees' gross pay (percent) | 150.00% | |||||
Defined contribution plan, period after which participant is fully vested in employer contributions | 3 years | |||||
Defined contribution plan, employer matching contribution cap | $ 2,200 | |||||
Union Participant [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined contribution plan, employer matching contribution, percent of employees' gross pay (percent) | 150.00% | |||||
Defined contribution plan, period after which participant is fully vested in employer contributions | 3 years | |||||
Defined contribution plan, employer matching contribution cap | $ 2,200 | |||||
Subsequent Event [Member] | Pension [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Pension Contributions | $ 5,000,000 | |||||
Subsequent Event [Member] | Pension [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Pension Contributions | $ 5,000,000 | |||||
Subsequent Event [Member] | SERP [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Estimated contribution to the defined benefit plans next year | $ 400,000 |
Benefit Plans (Pension and Post
Benefit Plans (Pension and Postretirement Benefit Plans' Obligations and Assets) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Noncurrent liabilities | $ (101.6) | $ (87.1) | |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Noncurrent liabilities | (101.6) | (87.1) | |
Postretirement [Member] | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Defined Benefit Plan, Funded Status of Plan | 15.8 | 15 | |
Postretirement [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Defined Benefit Plan, Funded Status of Plan | 15.8 | 15 | |
Pension [Member] | |||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | |||
Benefit obligation at January 1 | 410.8 | 443.8 | |
Service cost | 5.7 | 7.1 | $ 5.9 |
Interest cost | 14.7 | 17.3 | 17.5 |
Defined Benefit Plan, Curtailments | 2.5 | 0 | |
Actuarial (gain) / loss | 9 | (34.5) | |
Benefits paid | (23.1) | (22.9) | |
Benefit obligation at December 31 | 419.6 | 410.8 | 443.8 |
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value of plan assets at January 1 | 345.4 | 371.7 | |
Actual return / (loss) on plan assets | 13.3 | (8.8) | |
Contributions to plan assets | 5.4 | 5.4 | |
Fair value of plan assets at December 31 | 341 | 345.4 | 371.7 |
Defined Benefit Plan, Funded Status of Plan | (78.6) | (65.4) | |
Current liabilities | (0.4) | (0.4) | |
Noncurrent liabilities | (78.2) | (65) | |
Net asset / (liability) at December 31 | (78.6) | (65.4) | |
Prior service cost | 8.8 | 12 | |
Net actuarial loss | 108.9 | 94.7 | |
Accumulated other comprehensive income, regulatory assets and regulatory liabilities, pre-tax | 117.7 | 106.7 | |
Pension [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | |||
Benefit obligation at January 1 | 410.8 | 443.8 | |
Service cost | 5.7 | 7.1 | 5.9 |
Interest cost | 14.7 | 17.3 | 17.5 |
Defined Benefit Plan, Curtailments | 2.5 | 0 | |
Actuarial (gain) / loss | 9 | (34.5) | |
Benefits paid | (23.1) | (22.9) | |
Benefit obligation at December 31 | 419.6 | 410.8 | 443.8 |
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value of plan assets at January 1 | 345.4 | 371.7 | |
Actual return / (loss) on plan assets | 13.3 | (8.8) | |
Contributions to plan assets | 5.4 | 5.4 | |
Fair value of plan assets at December 31 | 341 | 345.4 | $ 371.7 |
Defined Benefit Plan, Funded Status of Plan | (78.6) | (65.4) | |
Current liabilities | (0.4) | (0.4) | |
Noncurrent liabilities | (78.2) | (65) | |
Net asset / (liability) at December 31 | (78.6) | (65.4) | |
Prior service cost | 10.8 | 17 | |
Net actuarial loss | 150.9 | 139.7 | |
Accumulated other comprehensive income, regulatory assets and regulatory liabilities, pre-tax | 161.7 | 156.7 | |
Regulatory Asset [Member] | Pension [Member] | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Accumulated other comprehensive income, regulatory assets and regulatory liabilities, pre-tax | 97.1 | 91.1 | |
Regulatory Asset [Member] | Pension [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Accumulated other comprehensive income, regulatory assets and regulatory liabilities, pre-tax | 97.1 | 91.1 | |
Regulatory Liability [Member] | Pension [Member] | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Accumulated other comprehensive income, regulatory assets and regulatory liabilities, pre-tax | 0 | 0 | |
Regulatory Liability [Member] | Pension [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Accumulated other comprehensive income, regulatory assets and regulatory liabilities, pre-tax | 0 | 0 | |
Accumulated Other Comprehensive Income/(Loss) [Member] | Pension [Member] | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Accumulated other comprehensive income, regulatory assets and regulatory liabilities, pre-tax | 20.6 | 15.6 | |
Accumulated Other Comprehensive Income/(Loss) [Member] | Pension [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Accumulated other comprehensive income, regulatory assets and regulatory liabilities, pre-tax | $ 64.6 | $ 65.6 |
Benefit Plans (Net Periodic Ben
Benefit Plans (Net Periodic Benefit Cost (Income)) (Details) - Pension [Member] - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Service cost | $ 5.7 | $ 7.1 | $ 5.9 |
Interest cost | 14.7 | 17.3 | 17.5 |
Expected return on assets | (22.8) | (22.6) | (22.9) |
Defined Benefit Plan, Curtailments | 3.8 | 0 | 0 |
Actuarial gain / (loss) | 4.3 | 5.8 | 3.4 |
Prior service cost | 1.8 | 2 | 1.5 |
Net Periodic benefit cost / (income) before adjustments | $ 7.5 | $ 9.6 | $ 5.4 |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 4.49% | 4.02% | 4.86% |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets | 6.50% | 6.50% | 6.75% |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Service cost | $ 5.7 | $ 7.1 | $ 5.9 |
Interest cost | 14.7 | 17.3 | 17.5 |
Expected return on assets | (22.8) | (22.6) | (22.9) |
Defined Benefit Plan, Curtailments | 5.7 | 0 | 0 |
Actuarial gain / (loss) | 7.2 | 9.8 | 6.4 |
Prior service cost | 3 | 3.3 | 2.8 |
Net Periodic benefit cost / (income) before adjustments | $ 13.5 | $ 14.9 | $ 9.7 |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 4.49% | 4.02% | 4.86% |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets | 6.50% | 6.50% | 6.75% |
Benefit Plans (Other Changes in
Benefit Plans (Other Changes in Plan Assets and Benefit Obligation Recognized in Accumulated Other Comprehensive Income, Regulatory Assets And Regulatory Liabilities) (Details) - Pension [Member] - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Defined Benefit Plan Disclosure [Line Items] | |||
Net actuarial (gain) / loss | $ 20.9 | $ (3) | $ 43.8 |
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Prior Service Cost (Credit), before Tax | 0 | 0 | 6.8 |
Defined Benefit Plan, Accumulated Other Comprehensive Income, Plan Curtailments | (3.8) | 0 | 0 |
Reversal of amortization item, Net actuarial (gain) / loss | (4.3) | (5.8) | (3.4) |
Reversal of amortization item, Prior service cost / (credit) | (1.8) | (2) | (1.5) |
Total recognized in Accumulated other comprehensive income, Regulatory assets and Regulatory liabilities | 11 | (10.8) | 45.7 |
Total recognized in net periodic benefit cost and Accumulated other comprehensive income, Regulatory assets and Regulatory liabilities | 18.5 | (1.2) | 51.1 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Net actuarial (gain) / loss | 20.9 | (3) | 43.8 |
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Prior Service Cost (Credit), before Tax | 0 | 0 | 6.8 |
Defined Benefit Plan, Accumulated Other Comprehensive Income, Plan Curtailments | (5.7) | 0 | 0 |
Reversal of amortization item, Net actuarial (gain) / loss | (7.2) | (9.8) | (6.4) |
Reversal of amortization item, Prior service cost / (credit) | (3) | (3.3) | (2.8) |
Total recognized in Accumulated other comprehensive income, Regulatory assets and Regulatory liabilities | 5 | (16.1) | 41.4 |
Total recognized in net periodic benefit cost and Accumulated other comprehensive income, Regulatory assets and Regulatory liabilities | $ 18.5 | $ (1.2) | $ 51.1 |
Benefit Plans (Estimated Amount
Benefit Plans (Estimated Amounts that will be Amortized from Accumulated Other Comprehensive Income, Regulatory Assets And Regulatory Liabilities) (Details) - Pension [Member] $ in Millions | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Defined Benefit Plan Disclosure [Line Items] | |
Net actuarial (gain) / loss | $ 5.8 |
Prior service cost | 1.4 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Net actuarial (gain) / loss | 9.7 |
Prior service cost | $ 1.9 |
Benefit Plans (Weighted Average
Benefit Plans (Weighted Average Assumptions Used to Determine Benefit Obligations) (Details) - Pension [Member] | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Defined Benefit Plan Disclosure [Line Items] | |||
Discount rate for obligations | 4.28% | 4.49% | 4.02% |
Rate of compensation increases | 3.94% | 3.94% | 3.94% |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount rate for obligations | 4.28% | 4.49% | 4.02% |
Rate of compensation increases | 3.94% | 3.94% | 3.94% |
Benefit Plans (Weighted Avera84
Benefit Plans (Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost (Income)) (Details) - Pension [Member] | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 4.49% | 4.02% | 4.86% |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets | 6.50% | 6.50% | 6.75% |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 4.49% | 4.02% | 4.86% |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets | 6.50% | 6.50% | 6.75% |
Benefit Plans (Defined Benefits
Benefit Plans (Defined Benefits Plan Assets, Target Allocations) (Details) | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Equity Securities [Member] | ||
Target Allocation | 38.00% | |
Percentage of plan assets | 37.00% | 17.00% |
Debt Securities [Member] | ||
Target Allocation | 56.00% | |
Percentage of plan assets | 53.00% | 67.00% |
Real Estate [Member] | ||
Target Allocation | 6.00% | |
Percentage of plan assets | 10.00% | 9.00% |
Other Investments [Member] | ||
Target Allocation | 0.00% | |
Percentage of plan assets | 0.00% | 7.00% |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Equity Securities [Member] | ||
Target Allocation | 38.00% | |
Percentage of plan assets | 37.00% | 17.00% |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Debt Securities [Member] | ||
Target Allocation | 56.00% | |
Percentage of plan assets | 53.00% | 67.00% |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Real Estate [Member] | ||
Target Allocation | 6.00% | |
Percentage of plan assets | 10.00% | 9.00% |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Other Investments [Member] | ||
Target Allocation | 0.00% | |
Percentage of plan assets | 0.00% | 7.00% |
Benefit Plans (Fair Value Measu
Benefit Plans (Fair Value Measurements for Pension Plan Assets) (Details) - Pension [Member] - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Defined Benefit Plan Disclosure [Line Items] | |||
Total Pension Plan Assets | $ 341 | $ 345.4 | $ 371.7 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Pension Plan Assets | 341 | 345.4 | $ 371.7 |
Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Pension Plan Assets | 307.9 | 292.4 | |
Fair Value, Inputs, Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Pension Plan Assets | 307.9 | 292.4 | |
Fair Value, Inputs, Level 2 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Pension Plan Assets | 33.1 | 53 | |
Fair Value, Inputs, Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Pension Plan Assets | 33.1 | 53 | |
Fair Value, Inputs, Level 3 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Pension Plan Assets | 0 | 0 | |
Fair Value, Inputs, Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Pension Plan Assets | 0 | 0 | |
U.S. Equities [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 81.4 | 39.4 | |
U.S. Equities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 81.4 | 39.4 | |
U.S. Equities [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 81.4 | 39.4 | |
U.S. Equities [Member] | Fair Value, Inputs, Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 81.4 | 39.4 | |
U.S. Equities [Member] | Fair Value, Inputs, Level 2 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 0 | 0 | |
U.S. Equities [Member] | Fair Value, Inputs, Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 0 | 0 | |
U.S. Equities [Member] | Fair Value, Inputs, Level 3 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 0 | 0 | |
U.S. Equities [Member] | Fair Value, Inputs, Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 0 | 0 | |
International Equities [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 44.4 | 20.9 | |
International Equities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 44.4 | 20.9 | |
International Equities [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 44.4 | 20.9 | |
International Equities [Member] | Fair Value, Inputs, Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 44.4 | 20.9 | |
International Equities [Member] | Fair Value, Inputs, Level 2 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 0 | 0 | |
International Equities [Member] | Fair Value, Inputs, Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 0 | 0 | |
International Equities [Member] | Fair Value, Inputs, Level 3 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 0 | 0 | |
International Equities [Member] | Fair Value, Inputs, Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 0 | 0 | |
Fixed Income Funds [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 151.1 | 232.1 | |
Fixed Income Funds [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 151.1 | 232.1 | |
Fixed Income Funds [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 151.1 | 232.1 | |
Fixed Income Funds [Member] | Fair Value, Inputs, Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 151.1 | 232.1 | |
Fixed Income Funds [Member] | Fair Value, Inputs, Level 2 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 0 | 0 | |
Fixed Income Funds [Member] | Fair Value, Inputs, Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 0 | 0 | |
Fixed Income Funds [Member] | Fair Value, Inputs, Level 3 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 0 | 0 | |
Fixed Income Funds [Member] | Fair Value, Inputs, Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 0 | 0 | |
US Treasury Securities [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Debt Securities | 31 | ||
US Treasury Securities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Debt Securities | 31 | ||
US Treasury Securities [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Debt Securities | 31 | ||
US Treasury Securities [Member] | Fair Value, Inputs, Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Debt Securities | 31 | ||
US Treasury Securities [Member] | Fair Value, Inputs, Level 2 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Debt Securities | 0 | ||
US Treasury Securities [Member] | Fair Value, Inputs, Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Debt Securities | 0 | ||
US Treasury Securities [Member] | Fair Value, Inputs, Level 3 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Debt Securities | 0 | ||
US Treasury Securities [Member] | Fair Value, Inputs, Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Debt Securities | 0 | ||
Core Property Collective Fund [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Other Investments | 33.1 | 30.2 | |
Core Property Collective Fund [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Other Investments | 33.1 | 30.2 | |
Core Property Collective Fund [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Other Investments | 0 | 0 | |
Core Property Collective Fund [Member] | Fair Value, Inputs, Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Other Investments | 0 | 0 | |
Core Property Collective Fund [Member] | Fair Value, Inputs, Level 2 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Other Investments | 33.1 | 30.2 | |
Core Property Collective Fund [Member] | Fair Value, Inputs, Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Other Investments | 33.1 | 30.2 | |
Core Property Collective Fund [Member] | Fair Value, Inputs, Level 3 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Other Investments | 0 | 0 | |
Core Property Collective Fund [Member] | Fair Value, Inputs, Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Other Investments | $ 0 | 0 | |
common collective [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Other Investments | 22.8 | ||
common collective [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Other Investments | 22.8 | ||
common collective [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Other Investments | 0 | ||
common collective [Member] | Fair Value, Inputs, Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Other Investments | 0 | ||
common collective [Member] | Fair Value, Inputs, Level 2 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Other Investments | 22.8 | ||
common collective [Member] | Fair Value, Inputs, Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Other Investments | 22.8 | ||
common collective [Member] | Fair Value, Inputs, Level 3 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Other Investments | 0 | ||
common collective [Member] | Fair Value, Inputs, Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Other Investments | $ 0 |
Benefit Plans (Estimated Future
Benefit Plans (Estimated Future Benefit Payments and Medicare Part D Reimbursements) (Details) - Pension [Member] $ in Millions | Dec. 31, 2016USD ($) |
2,016 | $ 25 |
2,017 | 25.5 |
2,018 | 26 |
2,019 | 26.4 |
2,020 | 26.7 |
2021 - 2025 | 139.6 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
2,016 | 25 |
2,017 | 25.5 |
2,018 | 26 |
2,019 | 26.4 |
2,020 | 26.7 |
2021 - 2025 | $ 139.6 |
Equity (Narrative) (Details)
Equity (Narrative) (Details) $ / shares in Units, $ in Millions | 12 Months Ended | |||
Dec. 31, 2016USD ($)fiscal_quarter$ / sharesshares | Dec. 31, 2015USD ($)$ / sharesshares | Dec. 31, 2014USD ($) | Jan. 01, 2016USD ($) | |
Class of Stock [Line Items] | ||||
Preferred stock dividends, number of quarters in arrears to trigger permission to elect board members | fiscal_quarter | 4 | |||
Maximum leverage ratio to allow distribution to shareholder | 0.67 | |||
Minimum coverage ratio to allow distribution to shareholder | 2.50 | |||
Retained earnings / (deficit) | $ | $ (2,820.9) | $ (2,335.7) | ||
Common stock, shares authorized | shares | 1,500 | 1,500 | ||
Common stock, shares outstanding | shares | 1 | 1 | ||
Leverage Ratio | 1.45 | |||
Accounts Payable, Related Parties, Current | $ | $ 2 | $ 0.5 | ||
PUCO Equity Ratio | 32.00% | |||
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Class of Stock [Line Items] | ||||
Preferred stock dividends, number of quarters in arrears to trigger permission to elect board members | fiscal_quarter | 4 | |||
Retained earnings / (deficit) | $ | $ (406.3) | $ 437.3 | ||
Common stock, shares authorized | shares | 250,000,000 | 250,000,000 | ||
Common stock, shares outstanding | shares | 41,172,173 | 41,172,173 | ||
PUCO Meger Equity Ratio Approval | 50.00% | |||
Accounts Payable, Related Parties, Current | $ | $ 2 | $ 0.5 | ||
PUCO Equity Ratio | 32.00% | |||
$100 Redeemable Preferred Stock [Member] | ||||
Class of Stock [Line Items] | ||||
Preferred stock par value | $ 100 | |||
Preferred stock shares outstanding | shares | 228,508 | |||
$100 Redeemable Preferred Stock [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Class of Stock [Line Items] | ||||
Preferred stock par value | $ 100 | |||
Preferred stock shares authorized | shares | 4,000,000 | |||
Preferred stock shares outstanding | shares | 228,508 | |||
$25 Redeemable Preferred Stock [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Class of Stock [Line Items] | ||||
Preferred stock par value | $ 25 | |||
Preferred stock shares authorized | shares | 4,000,000 | |||
DP&L Series A [Member] | ||||
Class of Stock [Line Items] | ||||
Temporary Equity, Preferred Stock Rate | 3.75% | 3.75% | ||
Temporary Equity, Redemption Price Per Share | $ 102.50 | $ 102.50 | ||
DP&L Series A [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Class of Stock [Line Items] | ||||
Temporary Equity, Preferred Stock Rate | 3.75% | 3.75% | ||
Temporary Equity, Redemption Price Per Share | $ 102.50 | $ 102.50 | ||
DP&L Series B [Member] | ||||
Class of Stock [Line Items] | ||||
Temporary Equity, Preferred Stock Rate | 3.75% | 3.75% | ||
Temporary Equity, Redemption Price Per Share | $ 103 | $ 103 | ||
DP&L Series B [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Class of Stock [Line Items] | ||||
Temporary Equity, Preferred Stock Rate | 3.75% | 3.75% | ||
Temporary Equity, Redemption Price Per Share | $ 103 | $ 103 | ||
DP&L Series C [Member] | ||||
Class of Stock [Line Items] | ||||
Temporary Equity, Preferred Stock Rate | 3.90% | 3.90% | ||
Temporary Equity, Redemption Price Per Share | $ 101 | $ 101 | ||
DP&L Series C [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Class of Stock [Line Items] | ||||
Temporary Equity, Preferred Stock Rate | 3.90% | 3.90% | ||
Temporary Equity, Redemption Price Per Share | $ 101 | $ 101 | ||
Subsidiary of Common Parent [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Class of Stock [Line Items] | ||||
Accounts Payable, Related Parties, Current | $ | $ 7.5 | |||
Equity Settlement of Related Party Payable | $ | $ 7.5 | $ 0 | $ 0 |
Equity (Preferred Shares Outsta
Equity (Preferred Shares Outstanding) (Details) - USD ($) $ / shares in Units, $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Temporary Equity [Line Items] | ||
Shares Outstanding | 228,508 | |
Carrying Value | $ 0 | $ 18.4 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Temporary Equity [Line Items] | ||
Par Value | $ 0 | $ 22.9 |
DP&L Series A [Member] | ||
Temporary Equity [Line Items] | ||
Temporary Equity, Preferred Stock Rate | 3.75% | 3.75% |
Temporary Equity, Redemption Price Per Share | $ 102.50 | $ 102.50 |
Shares Outstanding | 93,280 | |
Carrying Value | $ 0 | $ 7.4 |
DP&L Series A [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Temporary Equity [Line Items] | ||
Temporary Equity, Preferred Stock Rate | 3.75% | 3.75% |
Temporary Equity, Redemption Price Per Share | $ 102.50 | $ 102.50 |
Shares Outstanding | 93,280 | |
Par Value | $ 0 | $ 9.3 |
DP&L Series B [Member] | ||
Temporary Equity [Line Items] | ||
Temporary Equity, Preferred Stock Rate | 3.75% | 3.75% |
Temporary Equity, Redemption Price Per Share | $ 103 | $ 103 |
Shares Outstanding | 69,398 | |
Carrying Value | $ 0 | $ 5.6 |
DP&L Series B [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Temporary Equity [Line Items] | ||
Temporary Equity, Preferred Stock Rate | 3.75% | 3.75% |
Temporary Equity, Redemption Price Per Share | $ 103 | $ 103 |
Shares Outstanding | 69,398 | |
Par Value | $ 0 | $ 7 |
DP&L Series C [Member] | ||
Temporary Equity [Line Items] | ||
Temporary Equity, Preferred Stock Rate | 3.90% | 3.90% |
Temporary Equity, Redemption Price Per Share | $ 101 | $ 101 |
Shares Outstanding | 65,830 | |
Carrying Value | $ 0 | $ 5.4 |
DP&L Series C [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Temporary Equity [Line Items] | ||
Temporary Equity, Preferred Stock Rate | 3.90% | 3.90% |
Temporary Equity, Redemption Price Per Share | $ 101 | $ 101 |
Shares Outstanding | 65,830 | |
Par Value | $ 0 | $ 6.6 |
Contractual Obligations, Comm90
Contractual Obligations, Commercial Commitments and Contingencies (Narative) (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Public Utility, Property, Plant and Equipment [Line Items] | ||
Due to third parties, current | $ 2.3 | $ 0.5 |
Percentage of future committed coal | 92.00% | |
Number of Coal Suppliers | 2 | |
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Percentage of future committed coal | 92.00% | |
Number of Coal Suppliers | 2 | |
DPLE [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Third party guarantees | $ 16.6 | |
Debt Obligation on 4.9% Equity Ownership [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Equity ownership interest | 4.90% | |
Equity ownership interest aggregate cost | $ 74.2 | |
Long Term Debt Date Range Equity Ownership, Start | 2,017 | |
Long Term Debt Date Range Equity Ownership, End | 2,040 | |
Electric Generation Company [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Debt obligation | $ 1,514.3 |
Contractual Obligations, Comm91
Contractual Obligations, Commercial Commitments and Contingenciesl (Schedule Of Contractual Obligations And Commercial Commitments) (Details) $ in Millions | Dec. 31, 2016USD ($) |
Coal Contracts [Member] | |
Contractual Obligations, Commercial Commitments And Contingencies [Line Items] | |
Total Coal Contracts | $ 284.3 |
Coal Contracts, Less than 1 year | 230.3 |
Coal Contracts, 2 - 3 years | 54 |
Coal Contracts, 4 - 5 years | 0 |
Coal Contracts, More than 5 years | 0 |
Coal Contracts [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Contractual Obligations, Commercial Commitments And Contingencies [Line Items] | |
Total Coal Contracts | 284.3 |
Coal Contracts, Less than 1 year | 230.3 |
Coal Contracts, 2 - 3 years | 54 |
Coal Contracts, 4 - 5 years | 0 |
Coal Contracts, More than 5 years | 0 |
Other Intangible Assets [Member] | |
Contractual Obligations, Commercial Commitments And Contingencies [Line Items] | |
Total Purchase orders and other contractual obligations | 109.8 |
Purchase orders and other contractual obligations, Less than 1 year | 43.1 |
Purchase orders and other contractual obligations, 2 - 3 years | 33.6 |
Purchase orders and other contractual obligations, 4 - 5 years | 33.1 |
Purchase orders and other contractual obligations, More than 5 years | 0 |
Other Intangible Assets [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Contractual Obligations, Commercial Commitments And Contingencies [Line Items] | |
Total Purchase orders and other contractual obligations | 109.8 |
Purchase orders and other contractual obligations, Less than 1 year | 43.1 |
Purchase orders and other contractual obligations, 2 - 3 years | 33.6 |
Purchase orders and other contractual obligations, 4 - 5 years | 33.1 |
Purchase orders and other contractual obligations, More than 5 years | $ 0 |
Related Party Transactions (Det
Related Party Transactions (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Jan. 01, 2016 | |
Related Party Transaction [Line Items] | ||||
Deferred Compensation Arrangement with Individual, Compensation Expense | $ 0.5 | $ 0.5 | $ 0 | |
Sales to related party | 4.6 | 6.2 | 2.4 | |
Charges for Services Provided | 42.8 | 36 | 35.8 | |
Net payable to the Service Company | (2) | (0.5) | ||
Notes Receivable, Related Parties | 5 | 35 | ||
Investment in trust | 0.3 | 0.3 | ||
Due to Affiliate | (2.5) | (0.1) | ||
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Related Party Transaction [Line Items] | ||||
Deferred Compensation Arrangement with Individual, Compensation Expense | 0.5 | 0.5 | 0 | |
Sales to related party | 4.5 | 6.1 | 2.3 | |
Charges for Services Provided | 38.7 | 30.9 | 30.5 | |
Net payable to the Service Company | (2) | (0.5) | ||
Premiums paid for Insurance Services provided by MVIC | (3.4) | (3.2) | (2.9) | |
Expense recoveries for services provided to DPLER | 0 | 2.4 | 2.2 | |
Due to Affiliate | 2.5 | (0.1) | ||
Note to DPL Capital Trust II Maturing in 2031 - 8.125% [Member] | ||||
Related Party Transaction [Line Items] | ||||
Note payable to trust | 15.6 | 15.6 | ||
Prepayments and Other Current Assets [Member] | ||||
Related Party Transaction [Line Items] | ||||
Income tax receivable | 97.2 | 50.5 | ||
Prepayments and Other Current Assets [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Related Party Transaction [Line Items] | ||||
Income tax receivable | 9.5 | 1.5 | ||
DPLER [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Related Party Transaction [Line Items] | ||||
Sales to related party | 0 | 303.3 | 487.1 | |
Subsidiary of Common Parent [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Related Party Transaction [Line Items] | ||||
Net payable to the Service Company | $ (7.5) | |||
Charges for health, welfare and benefit plans [Member] | Subsidiary of Common Parent [Member] | ||||
Related Party Transaction [Line Items] | ||||
Related Party Transaction, Amounts of Transaction | 9.6 | 15.5 | 17.8 | |
Charges for health, welfare and benefit plans [Member] | Subsidiary of Common Parent [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Related Party Transaction [Line Items] | ||||
Related Party Transaction, Amounts of Transaction | $ 9.4 | $ 14.8 | $ 17.1 |
Business Segments (Narrative) (
Business Segments (Narrative) (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016mi²customersegment | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | |
Segment Reporting Information [Line Items] | |||
Service area, square miles | mi² | 6,000 | ||
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Segment Reporting Information [Line Items] | |||
Number of Operating Segments | segment | 2 | ||
Approximate number of retail customers | customer | 519,000 | ||
Service area, square miles | mi² | 6,000 | ||
Transmission and Distribution [Member] | Operating Segments [Member] | |||
Segment Reporting Information [Line Items] | |||
OVEC Revenue | $ | $ 19.7 | $ 32.5 | |
Transmission and Distribution [Member] | Operating Segments [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Segment Reporting Information [Line Items] | |||
OVEC Revenue | $ | $ 19.7 | $ 32.5 |
Business Segments (Segment Fina
Business Segments (Segment Financial Information) (Details) - USD ($) $ in Millions | 6 Months Ended | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Segment Reporting Information [Line Items] | ||||
External customer revenues | $ 1,427.3 | $ 1,612.8 | $ 1,716.5 | |
Intersegment revenues | 0 | 0 | 0 | |
Total revenues | 1,427.3 | 1,612.8 | 1,716.5 | |
Fuel Costs | 268.8 | 259.8 | 304.5 | |
Amortization of intangibles | 0 | 0 | 1.2 | |
Depreciation and amortization | 132.3 | 134.6 | 135.6 | |
Goodwill impairment (Note 7) | 0 | 317 | 0 | |
Interest expense | 106.1 | 118.3 | 126.6 | |
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest | (793.3) | (231.4) | 72.6 | |
Net loss from continuing operations | (514.5) | (251.4) | 57.2 | |
Discontinued operations, net of tax | 29.3 | 12.4 | (131.8) | |
Net income (loss) | (485.2) | (239) | (74.6) | |
Cash capital expenditures | 148.5 | 137.2 | 118.1 | |
Total assets (end of year) (a) | $ 2,419.2 | 2,419.2 | 3,324.7 | 3,559.1 |
Fixed-asset impairment (Note 15) | 623.5 | 859 | 0 | 11.5 |
Operating Segments [Member] | Transmission and Distribution [Member] | ||||
Segment Reporting Information [Line Items] | ||||
OVEC Revenue | 19.7 | 32.5 | ||
External customer revenues | 806.7 | 855.5 | 1,020.1 | |
Intersegment revenues | 1.3 | 1.5 | 1.7 | |
Total revenues | 808 | 857 | 1,021.8 | |
Depreciation and amortization | 71 | 71.5 | 75.5 | |
Goodwill impairment (Note 7) | 0 | |||
Interest expense | 24.7 | 28.9 | 29.8 | |
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest | 143 | 188.1 | 241.7 | |
Cash capital expenditures | 83.4 | 98.3 | 100.4 | |
Total assets (end of year) (a) | 1,710.5 | 1,710.5 | 1,688.8 | 1,686.1 |
Fixed-asset impairment (Note 15) | 0 | 0 | ||
Operating Segments [Member] | Generation [Member] | ||||
Segment Reporting Information [Line Items] | ||||
External customer revenues | 611.5 | 770.3 | 721.8 | |
Intersegment revenues | 0 | 186.6 | 72.8 | |
Total revenues | 611.5 | 956.9 | 794.6 | |
Depreciation and amortization | 55.4 | 72.6 | 75.3 | |
Goodwill impairment (Note 7) | 0 | |||
Interest expense | 0.4 | 2.9 | 5 | |
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest | (1,353.9) | (28.7) | (78) | |
Cash capital expenditures | 64.2 | 35.2 | 14.5 | |
Total assets (end of year) (a) | 472.3 | 472.3 | 1,805 | 1,771.4 |
Fixed-asset impairment (Note 15) | 1,353.5 | 0 | ||
Corporate, Non-Segment [Member] | ||||
Segment Reporting Information [Line Items] | ||||
External customer revenues | 9.1 | 6.7 | 7.1 | |
Intersegment revenues | 5.7 | 4.2 | 3.8 | |
Total revenues | 14.8 | 10.9 | 10.9 | |
Depreciation and amortization | 5.9 | (9.5) | (15.2) | |
Goodwill impairment (Note 7) | 317 | |||
Interest expense | 81.3 | 86.8 | 92.5 | |
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest | 417.6 | (390.8) | (91.1) | |
Cash capital expenditures | 0.9 | 3.7 | 3.2 | |
Total assets (end of year) (a) | 673.6 | 673.6 | 1,170.3 | 1,397.5 |
Fixed-asset impairment (Note 15) | (494.5) | 11.5 | ||
Consolidation, Eliminations [Member] | ||||
Segment Reporting Information [Line Items] | ||||
External customer revenues | 0 | (19.7) | (32.5) | |
Intersegment revenues | (7) | (192.3) | (78.3) | |
Total revenues | (7) | (212) | (110.8) | |
Depreciation and amortization | 0 | 0 | 0 | |
Goodwill impairment (Note 7) | 0 | |||
Interest expense | (0.3) | (0.3) | (0.7) | |
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest | 0 | 0 | 0 | |
Cash capital expenditures | 0 | 0 | 0 | |
Total assets (end of year) (a) | (437.2) | (437.2) | (1,339.4) | (1,295.9) |
Fixed-asset impairment (Note 15) | 0 | 0 | ||
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Segment Reporting Information [Line Items] | ||||
External customer revenues | 1,365.9 | 1,552.3 | 1,668.3 | |
Intersegment revenues | 0 | 0 | 0 | |
Total revenues | 1,365.9 | 1,552.3 | 1,668.3 | |
Fuel Costs | 248.9 | 244.7 | 314.9 | |
Depreciation and amortization | 120.3 | 138.2 | 144.8 | |
Interest expense | 24.5 | 30.9 | 33.9 | |
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest | (1,195.1) | 141.5 | 154.7 | |
Net income (loss) | (772.7) | 106.4 | 115 | |
Cash capital expenditures | 128.3 | 127 | 114.2 | |
Total assets (end of year) (a) | 2,035.1 | 2,035.1 | 3,359.6 | 3,328.8 |
Fixed-asset impairment (Note 15) | 496.4 | 1,353.5 | 0 | 0 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Operating Segments [Member] | Transmission and Distribution [Member] | ||||
Segment Reporting Information [Line Items] | ||||
OVEC Revenue | 19.7 | 32.5 | ||
External customer revenues | 808 | 857 | 1,021.8 | |
Intersegment revenues | 0 | 0 | 0 | |
Total revenues | 808 | 857 | 1,021.8 | |
Depreciation and amortization | 71 | 71.5 | 75.5 | |
Interest expense | 24 | 28 | 28.9 | |
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest | 143.6 | 189 | 242.6 | |
Cash capital expenditures | 83.4 | 98.3 | 100.4 | |
Total assets (end of year) (a) | 1,710.5 | 1,710.5 | 1,688.8 | 1,686.1 |
Fixed-asset impairment (Note 15) | 0 | |||
THE DAYTON POWER AND LIGHT COMPANY [Member] | Operating Segments [Member] | Generation [Member] | ||||
Segment Reporting Information [Line Items] | ||||
External customer revenues | 557.9 | 715 | 679 | |
Intersegment revenues | 0 | 186.6 | 72.8 | |
Total revenues | 557.9 | 901.6 | 751.8 | |
Depreciation and amortization | 49.3 | 66.7 | 69.3 | |
Interest expense | 0.5 | 2.9 | 5 | |
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest | (1,338.7) | (47.5) | (87.9) | |
Cash capital expenditures | 44.9 | 28.7 | 13.8 | |
Total assets (end of year) (a) | 324.6 | 324.6 | 1,670.8 | 1,642.7 |
Fixed-asset impairment (Note 15) | 1,353.5 | |||
THE DAYTON POWER AND LIGHT COMPANY [Member] | Consolidation, Eliminations [Member] | ||||
Segment Reporting Information [Line Items] | ||||
External customer revenues | 0 | (19.7) | (32.5) | |
Intersegment revenues | 0 | (186.6) | (72.8) | |
Total revenues | 0 | (206.3) | (105.3) | |
Depreciation and amortization | 0 | 0 | 0 | |
Interest expense | 0 | 0 | 0 | |
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest | 0 | 0 | 0 | |
Cash capital expenditures | 0 | 0 | 0 | |
Total assets (end of year) (a) | $ 0 | 0 | $ 0 | $ 0 |
Fixed-asset impairment (Note 15) | $ 0 |
Fixed-asset Impairment (Narrati
Fixed-asset Impairment (Narrative) (Details) $ in Millions | 3 Months Ended | 6 Months Ended | 12 Months Ended | |||
Mar. 31, 2014USD ($)MW | Dec. 31, 2016USD ($) | Jun. 30, 2016USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | |
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fixed-asset impairment (Note 15) | $ 623.5 | $ 859 | $ 0 | $ 11.5 | ||
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fixed-asset impairment (Note 15) | 496.4 | 1,353.5 | $ 0 | 0 | ||
Zimmer [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fixed-asset impairment (Note 15) | 144.7 | |||||
Zimmer [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fixed-asset impairment (Note 15) | 91.3 | $ 318.9 | 318.9 | |||
Conesville [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fixed-asset impairment (Note 15) | 23.9 | |||||
Conesville [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fixed-asset impairment (Note 15) | 20.8 | |||||
Hutchings Peakers [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fixed-asset impairment (Note 15) | 1.6 | |||||
Hutchings Peakers [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fixed-asset impairment (Note 15) | 1.4 | |||||
Stuart [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fixed-asset impairment (Note 15) | 228.5 | |||||
Stuart [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fixed-asset impairment (Note 15) | 149.9 | 292 | 292 | |||
Killen [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fixed-asset impairment (Note 15) | 75.4 | 230.8 | ||||
Killen [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fixed-asset impairment (Note 15) | 75.3 | 246.2 | 246.2 | |||
Peaking Generating Facilities [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fixed-asset impairment (Note 15) | 4.7 | |||||
Miami Fort [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fixed-asset impairment (Note 15) | 149.4 | |||||
Miami Fort [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fixed-asset impairment (Note 15) | 157.7 | |||||
East Bend Station [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fixed-asset impairment (Note 15) | $ 11.5 | 0 | 11.5 | |||
Fair Value | 2.7 | |||||
East Bend Station [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Production Plan Capacity | MW | 186 | |||||
Fair Value, Inputs, Level 3 [Member] | Zimmer [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fair Value | 23.7 | 23.7 | ||||
Fair Value, Inputs, Level 3 [Member] | Zimmer [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fair Value | 23.7 | 111 | 23.7 | |||
Fair Value, Inputs, Level 3 [Member] | Conesville [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fair Value | 1.1 | 1.1 | ||||
Fair Value, Inputs, Level 3 [Member] | Conesville [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fair Value | 1.1 | 1.1 | ||||
Fair Value, Inputs, Level 3 [Member] | Hutchings Peakers [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fair Value | 1.6 | 1.6 | ||||
Fair Value, Inputs, Level 3 [Member] | Hutchings Peakers [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fair Value | 1.6 | 1.6 | ||||
Fair Value, Inputs, Level 3 [Member] | Stuart [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fair Value | 57.4 | 57.4 | ||||
Fair Value, Inputs, Level 3 [Member] | Stuart [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fair Value | 57.4 | 164.4 | 57.4 | |||
Fair Value, Inputs, Level 3 [Member] | Killen [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fair Value | 42.8 | 84.3 | 42.8 | |||
Fair Value, Inputs, Level 3 [Member] | Killen [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fair Value | 42.8 | 84.3 | 42.8 | |||
Fair Value, Inputs, Level 3 [Member] | Peaking Generating Facilities [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fair Value | $ 5.2 | |||||
Fair Value, Inputs, Level 3 [Member] | Miami Fort [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fair Value | 36.5 | 36.5 | ||||
Fair Value, Inputs, Level 3 [Member] | Miami Fort [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fair Value | $ 36.5 | $ 36.5 | ||||
Fair Value, Inputs, Level 3 [Member] | East Bend Station [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fair Value | $ 2.7 |
Discontinued Operations (Detail
Discontinued Operations (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Deposit received on sale of DPLER | $ 0 | $ 75.5 | |
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax | 49.2 | 0 | $ 0 |
Accounts receivable, net | 31 | ||
Property, plant & equipment, net | 1.1 | ||
Intangible assets, net | 28.1 | ||
Other assets | 2 | ||
Total assets of the disposal group classified as held for sale in the balance sheets | 62.2 | ||
Accounts payable | 0.8 | ||
Other liabilities | 0.8 | ||
Total liabilities of the disposal group classified as held for sale in the balance sheets | 1.6 | ||
Revenues | 0 | 340.9 | 533.6 |
Cost of revenues | 0 | (307) | (493) |
Operating expenses | (0.7) | (22.5) | (34) |
Goodwill impairment | 0 | 0 | (135.8) |
Profit / (loss) of discontinued operations before income taxes | (0.7) | 11.4 | (129.2) |
Income tax expense / (benefit) | 19.2 | (1) | 2.6 |
Net income / (loss) from discontinued operations | 29.3 | 12.4 | (131.8) |
Cash provided by (used in) operating activities, discontinued operations | (0.7) | 35.8 | 29.6 |
Cash provided by (used in) investing activities, discontinued operations | 75.5 | $ 0.5 | $ (2.2) |
DPLER [Member] | |||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Deposit received on sale of DPLER | $ 75.5 |
Schedule II Valuation And Qua97
Schedule II Valuation And Qualifying Accounts (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Provision for Uncollectible Accounts [Member] | |||
Valuation and Qualifying Accounts Disclosure [Line Items] | |||
Balance at Beginning of Period | $ 835 | $ 898 | $ 909 |
Additions | 4,113 | 3,766 | 4,011 |
Deductions | 3,789 | 3,829 | 4,022 |
Balance at End of Period | 1,159 | 835 | 898 |
Provision for Uncollectible Accounts [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Valuation and Qualifying Accounts Disclosure [Line Items] | |||
Balance at Beginning of Period | 835 | 897 | 909 |
Additions | 4,113 | 3,766 | 4,011 |
Deductions | 3,789 | 3,828 | 4,023 |
Balance at End of Period | 1,159 | 835 | 897 |
Valuation Allowance For Deferred Tax Assets [Member] | |||
Valuation and Qualifying Accounts Disclosure [Line Items] | |||
Balance at Beginning of Period | 17,246 | 18,900 | 13,721 |
Additions | 0 | 1,626 | 5,179 |
Deductions | 13,921 | 3,280 | 0 |
Balance at End of Period | 3,325 | 17,246 | 18,900 |
Assets held for sale, current [Member] | Provision for Uncollectible Accounts [Member] | |||
Valuation and Qualifying Accounts Disclosure [Line Items] | |||
Balance at Beginning of Period | $ 113 | 369 | 251 |
Additions | 2,035 | 3,633 | |
Deductions | 2,291 | 3,515 | |
Balance at End of Period | $ 113 | $ 369 |