Document and Entity Information
Document and Entity Information | 12 Months Ended |
Dec. 31, 2017USD ($)shares | |
Entity Registrant Name | DPL INC |
Entity Central Index Key | 787,250 |
Document Type | 10-K |
Document Period End Date | Dec. 31, 2017 |
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 | 2,017 |
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 | THE DAYTON POWER & LIGHT CO |
Entity Central Index Key | 27,430 |
Document Type | 10-K |
Document Period End Date | Dec. 31, 2017 |
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 | 2,017 |
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, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Revenues | $ 1,236.9 | $ 1,427.3 | $ 1,612.8 |
Cost of revenues: | |||
Net fuel cost | 210.3 | 268.8 | 259.8 |
Net purchased power cost | 339.2 | 417.4 | 562.6 |
Total cost of revenues | 549.5 | 686.2 | 822.4 |
Gross margin | 687.4 | 741.1 | 790.4 |
Operating expenses: | |||
Operation and maintenance | 327.6 | 348.1 | 361.3 |
Depreciation and amortization | 106.9 | 132.3 | 134.6 |
General taxes | 89.7 | 85.7 | 87 |
Goodwill impairment (Note 7) | 0 | 0 | 317 |
Fixed-asset impairment (Note 15) | 175.8 | 859 | 0 |
Gain (Loss) on Sale of Assets and Asset Impairment Charges, excluding Discontinued Operations | (6.6) | (0.1) | 0.4 |
Total operating expenses | 693.4 | 1,425 | 900.3 |
Operating loss | (6) | (683.9) | (109.9) |
Other income / (expense), net | |||
Investment income | 0.3 | 0.4 | 0.2 |
Interest expense | (110.1) | (107.7) | (119.8) |
Charge for early redemption of debt | (3.3) | (3.1) | (2.1) |
Other income / (expense) | (0.8) | 1 | 0.2 |
Other expense, net | (113.9) | (109.4) | (121.5) |
Loss from continuing operations before income tax | (119.9) | (793.3) | (231.4) |
Income tax expense / (benefit) from continuing operations | (25.3) | (278.8) | 20 |
Net loss from continuing operations | (94.6) | (514.5) | (251.4) |
Income / (loss) from discontinued operations | 0 | (0.7) | 11.4 |
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax | 0 | 49.2 | 0 |
Income tax expense / (benefit) from discontinued operations | 0 | 19.2 | (1) |
Net income from discontinued operations | 0 | 29.3 | 12.4 |
Net loss | (94.6) | (485.2) | (239) |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Revenues | 720 | 808 | 857 |
Cost of revenues: | |||
Net fuel cost | 0.5 | 5.3 | (9) |
Net purchased power cost | 289.8 | 316.7 | 317.4 |
Total cost of revenues | 290.3 | 322 | 308.4 |
Gross margin | 429.7 | 486 | 548.6 |
Operating expenses: | |||
Operation and maintenance | 158 | 179.3 | 184 |
Depreciation and amortization | 75.3 | 71 | 71.5 |
General taxes | 76.3 | 68 | 70.8 |
Fixed-asset impairment (Note 15) | 66.3 | 1,353.5 | 0 |
Gain (Loss) on Sale of Assets and Asset Impairment Charges, excluding Discontinued Operations | (0.5) | (0.4) | 0.1 |
Total operating expenses | 309.1 | 317.9 | 326.4 |
Operating loss | 120.6 | 168.1 | 222.2 |
Other income / (expense), net | |||
Investment income | 0.3 | 0.4 | 0.3 |
Interest expense | (30.5) | (24.7) | (28.9) |
Charge for early redemption of debt | (1.1) | (0.5) | (4.8) |
Other income / (expense) | (0.8) | 0.3 | 0.2 |
Other expense, net | (32.1) | (24.5) | (33.2) |
Loss from continuing operations before income tax | 88.5 | 143.6 | 189 |
Income tax expense / (benefit) from continuing operations | 31.1 | 46 | 59 |
Net loss from continuing operations | 57.4 | 97.6 | 130 |
Income / (loss) from discontinued operations | (56.3) | (1,338.7) | (47.5) |
Income tax expense / (benefit) from discontinued operations | (15.9) | (468.4) | (23.9) |
Net income from discontinued operations | (40.4) | (870.3) | (23.6) |
Dividends on preferred stock | 0 | 0.7 | 0.9 |
Income / (loss) attributable to common stock | 17 | (773.4) | 105.5 |
Net loss | $ 17 | $ (772.7) | $ 106.4 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income/(Loss) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Net loss | $ (94.6) | $ (485.2) | $ (239) |
Available-for-sale securities activity: | |||
Change in fair value of available-for-sale securities, net of income tax benefit/(expense) | 0.5 | 0.2 | (0.1) |
Reclassification to earnings of available-for-sale securities, net of income tax expense/(benefit) | (0.1) | 0 | 0 |
Total change in fair value of available-for-sale securities | 0.4 | 0.2 | (0.1) |
Derivative activity: | |||
Change in derivative fair value, net of income tax benefit/(expense) | 9.6 | 16.1 | 18.2 |
Reclassification of earnings, net of income tax benefit/(expense) | (8) | (29.7) | (10) |
Total change in fair value of derivatives | 1.6 | (13.6) | 8.2 |
Pension and postretirement activity: | |||
Prior service cost for the period, net of income tax benefit/(expense) | (0.7) | 0 | 0 |
Net loss for the period, net of income tax benefit/(expense) | (1.8) | (4.7) | 1.6 |
Reclassification to earnings, net of income tax benefit/(expense) | 1 | 1 | 0.2 |
Total change in unfunded pension obligation | (1.5) | (3.7) | 1.8 |
Other comprehensive income / (loss) | 0.5 | (17.1) | 9.9 |
Net comprehensive income / (loss) | (94.1) | (502.3) | (229.1) |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Net loss | 17 | (772.7) | 106.4 |
Available-for-sale securities activity: | |||
Change in fair value of available-for-sale securities, net of income tax benefit/(expense) | 0.5 | 0.2 | (0.2) |
Reclassification to earnings of available-for-sale securities, net of income tax expense/(benefit) | (0.1) | 0 | 0 |
Total change in fair value of available-for-sale securities | 0.4 | 0.2 | (0.2) |
Derivative activity: | |||
Change in derivative fair value, net of income tax benefit/(expense) | 12.4 | 16.1 | 18.2 |
Reclassification of earnings, net of income tax benefit/(expense) | (6.2) | (30) | (9.8) |
Total change in fair value of derivatives | 6.2 | (13.9) | 8.4 |
Pension and postretirement activity: | |||
Prior service cost for the period, net of income tax benefit/(expense) | (1.9) | (0.1) | 0 |
Net loss for the period, net of income tax benefit/(expense) | (0.8) | (5.9) | 1.7 |
Reclassification to earnings, net of income tax benefit/(expense) | 4.5 | 5.9 | 3.7 |
Total change in unfunded pension obligation | 1.8 | (0.1) | 5.4 |
Other comprehensive income / (loss) | 8.4 | (13.8) | 13.6 |
Net comprehensive income / (loss) | $ 25.4 | $ (786.5) | $ 120 |
Consolidated Statements of Com4
Consolidated Statements of Comprehensive Income/(Loss) (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Income tax (expense)/benefit on unrealized gains (losses) related to available-for-sale securities | $ (0.2) | $ (0.1) | $ 0.1 |
Other Comprehensive Income (Loss), Reclassification Adjustment for Sale of Securities Included in Net Income, Tax | 0 | 0 | 0 |
Income tax (expense)/benefit on unrealized gains (losses) related to derivative activity | (5.3) | (8.8) | (10.3) |
Income tax (expense)/benefit on reclassification of earnings related to derivative activity | 4.4 | 16.7 | 5.4 |
Income tax (expense)/benefit on prior service cost related to pension and postretirement activity | 0.4 | 0 | 0 |
Income tax (expense)/benefit on net loss related to pension and postretirement activity | 1.1 | 2.4 | (1.2) |
Income tax (expense)/benefit on reclassification of earnings related to pension and postretirement activity | (0.5) | (0.6) | (0.2) |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Income tax (expense)/benefit on unrealized gains (losses) related to available-for-sale securities | (0.2) | (0.1) | 0.1 |
Other Comprehensive Income (Loss), Reclassification Adjustment for Sale of Securities Included in Net Income, Tax | 0 | 0 | 0 |
Income tax (expense)/benefit on unrealized gains (losses) related to derivative activity | (7.2) | (8.7) | (10.3) |
Income tax (expense)/benefit on reclassification of earnings related to derivative activity | 3.2 | 16.4 | 5.6 |
Income tax (expense)/benefit on prior service cost related to pension and postretirement activity | 1 | 0 | 0 |
Income tax (expense)/benefit on net loss related to pension and postretirement activity | 0.4 | 1.1 | (1) |
Income tax (expense)/benefit on reclassification of earnings related to pension and postretirement activity | $ (2.3) | $ (1.8) | $ (1.9) |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Current assets: | ||
Cash and cash equivalents | $ 24.5 | $ 54.6 |
Restricted cash | 1.9 | 29 |
Accounts receivable, net | 98.7 | 135.1 |
Inventories | 24.5 | 77.2 |
Taxes applicable to subsequent years | 73.8 | 81 |
Regulatory assets, current | 23.9 | 0.1 |
Other prepayments and current assets | 27.9 | 31.8 |
Assets held for sale - current | 250.3 | 0 |
Total current assets | 525.5 | 408.8 |
Property, plant and equipment: | ||
Property, plant and equipment | 1,554.7 | 1,985.6 |
Less: Accumulated depreciation and amortization | (278.6) | (334.8) |
Property, plant and equipment, net of depreciation | 1,276.1 | 1,650.8 |
Construction work in process | 48.8 | 116.4 |
Total net property, plant and equipment | 1,324.9 | 1,767.2 |
Other non-current assets: | ||
Regulatory assets, non-current | 163.2 | 203.9 |
Intangible assets, net of amortization | 21.1 | 22.7 |
Other deferred assets | 14.5 | 16.6 |
Total other non-current assets | 198.8 | 243.2 |
Total Assets | 2,049.2 | 2,419.2 |
LIABILITIES AND SHAREHOLDER'S EQUITY | ||
Current portion - long-term debt | 4.7 | 29.7 |
Short-term debt | 10 | 0 |
Accounts payable | 70.1 | 113.9 |
Accrued taxes | 80 | 185.1 |
Accrued interest | 16.4 | 17.7 |
Customer security deposits | 21.8 | 15.2 |
Regulatory liabilities, current | 14.8 | 33.7 |
Insurance and claims costs | 3 | 5.4 |
Other current liabilities | 42.8 | 50.2 |
Liabilities held for sale - current | 13.2 | 0 |
Total current liabilities | 276.8 | 450.9 |
Non-current liabilities: | ||
Long-term debt | 1,700.4 | 1,828.7 |
Deferred taxes | 111.2 | 252.4 |
Taxes payable | 77.4 | 84.6 |
Regulatory liabilities, non-current | 221.2 | 130.4 |
Pension, retiree and other benefits | 101 | 101.6 |
Asset Retirement Obligations, Noncurrent | 131.2 | 138.8 |
Other deferred credits | 14.3 | 19.4 |
Total non-current liabilities | 2,356.7 | 2,555.9 |
Commitments and contingencies | ||
Common shareholder's equity: | ||
Common stock | 0 | 0 |
Other paid-in capital | 2,330.4 | 2,233 |
Accumulated other comprehensive income/(loss) | 0.8 | 0.3 |
Retained earnings / (deficit) | (2,915.5) | (2,820.9) |
Total common shareholder's equity | (584.3) | (587.6) |
Total Liabilities and Shareholder's Equity | 2,049.2 | 2,419.2 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Current assets: | ||
Cash and cash equivalents | 5.2 | 1.6 |
Restricted cash | 0.4 | 0 |
Accounts receivable, net | 70.8 | 99.8 |
Inventories | 7.3 | 9.3 |
Taxes applicable to subsequent years | 71.1 | 67.9 |
Regulatory assets, current | 23.9 | 0.1 |
Other prepayments and current assets | 14.6 | 9.5 |
Assets held for sale - current | 0 | 324.6 |
Total current assets | 193.3 | 512.8 |
Property, plant and equipment: | ||
Property, plant and equipment | 2,247.2 | 2,213.5 |
Less: Accumulated depreciation and amortization | (987.3) | (968.9) |
Property, plant and equipment, net of depreciation | 1,259.9 | 1,244.6 |
Construction work in process | 41.5 | 39.3 |
Total net property, plant and equipment | 1,301.4 | 1,283.9 |
Other non-current assets: | ||
Regulatory assets, non-current | 163.2 | 203.9 |
Intangible assets, net of amortization | 18.8 | 22.1 |
Other deferred assets | 12.7 | 12.4 |
Total other non-current assets | 194.7 | 238.4 |
Total Assets | 1,689.4 | 2,035.1 |
LIABILITIES AND SHAREHOLDER'S EQUITY | ||
Current portion - long-term debt | 4.6 | 4.6 |
Short-term debt | 10 | 5 |
Accounts payable | 46.6 | 55.7 |
Accrued taxes | 70.1 | 72.2 |
Accrued interest | 0.8 | 2.1 |
Customer security deposits | 21.8 | 15.2 |
Regulatory liabilities, current | 14.8 | 33.7 |
Other current liabilities | 12.9 | 15.2 |
Liabilities held for sale - current | 0 | 157.7 |
Total current liabilities | 181.6 | 361.4 |
Non-current liabilities: | ||
Long-term debt | 642 | 731.5 |
Deferred taxes | 131 | 266.9 |
Taxes payable | 75.8 | 72.8 |
Regulatory liabilities, non-current | 221.2 | 130.4 |
Pension, retiree and other benefits | 91.1 | 93.4 |
Unamortized investment tax credit | 0.9 | 1.1 |
Asset Retirement Obligations, Noncurrent | 8 | 8.2 |
Other deferred credits | 7.1 | 7.1 |
Total non-current liabilities | 1,177.1 | 1,311.4 |
Commitments and contingencies | ||
Common shareholder's equity: | ||
Common stock | 0.4 | 0.4 |
Other paid-in capital | 685.8 | 810.7 |
Accumulated other comprehensive income/(loss) | (36.2) | (42.5) |
Retained earnings / (deficit) | (319.3) | (406.3) |
Total common shareholder's equity | 330.7 | 362.3 |
Total Liabilities and Shareholder's Equity | $ 1,689.4 | $ 2,035.1 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Dec. 31, 2017 | Dec. 31, 2016 |
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, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Cash flows from operating activities: | |||
Net income (loss) | $ (94.6) | $ (485.2) | $ (239) |
Adjustments to reconcile Net loss to Net cash from operating activities | |||
Depreciation and amortization | 106.9 | 132.3 | 138.8 |
Amortization of debt market value adjustments | 0.1 | 0.1 | (1.1) |
Amortization of deferred financing costs | 3.6 | 5.6 | 5.9 |
Unrealized loss (gain) on derivatives | (1.7) | (4.3) | 5.8 |
Deferred income taxes | (22.2) | (306.2) | (17.1) |
Charge for early redemption of debt | 3.3 | 3.1 | 2.1 |
Goodwill impairment | 0 | 0 | 317 |
Fixed-asset impairment (Note 15) | 175.8 | 859 | 0 |
Loss / (Gain) on asset disposal | 2.2 | (49.2) | 0.4 |
Changes in certain assets and liabilities: | |||
Accounts receivable | 16.8 | 24.2 | 43.4 |
Inventories | 7.7 | 32 | (9) |
Prepaid taxes | 0 | 0.2 | (1.3) |
Taxes applicable to subsequent years | 2.3 | 0.2 | (3.4) |
Deferred regulatory costs, net | (23.7) | 4.1 | 21.8 |
Accounts payable | (35) | 16.5 | (5.1) |
Accrued taxes payable | (3.7) | 45.1 | 43.8 |
Accrued interest payable | (1.3) | (3.7) | (5.7) |
Pension, retiree and other benefits | 4.5 | 8.6 | (0.7) |
Unamortized investment tax credit | (0.3) | (0.4) | (0.5) |
Insurance and claims costs | (2.4) | (0.5) | (0.5) |
Other | (6.6) | (14.4) | 12.9 |
Net cash provided by operating activities | 131.7 | 267.1 | 308.5 |
Cash flows from investing activities: | |||
Capital expenditures | (121.5) | (148.5) | (137.2) |
Proceeds from sale of business | 70.1 | 75.5 | 1.3 |
Insurance proceeds | 12.3 | 6.3 | 0 |
Purchase of renewable energy credits | (0.6) | (0.4) | (0.8) |
Decrease / (increase) in restricted cash | 27.1 | (11.8) | (0.4) |
Other investing activities, net | 0.4 | 1.1 | 0.4 |
Net cash used in investing activities | (12.2) | (77.8) | (136.7) |
Cash flows from financing activities: | |||
Deferred financing costs | 0 | (8.6) | (6.9) |
Preferred Stock, Redemption Amount | 0 | (23.5) | 0 |
Retirement of debt | (159.5) | (577.8) | (474.5) |
Premium paid for early redemption of debt | (0.1) | 0 | 0 |
Issuance of long-term debt | 0 | 442.8 | 325 |
Borrowings from revolving credit facilities | 102.5 | 15 | 80 |
Repayment of borrowings from revolving credit facilities | (92.5) | (15) | (80) |
Net cash from financing activities | (149.6) | (167.1) | (156.4) |
Cash and cash equivalents: | |||
Net increase / (decrease) in cash | (30.1) | 22.2 | 15.4 |
Balance at beginning of period | 54.6 | 32.4 | 17 |
Cash and cash equivalents at end of period | 24.5 | 54.6 | 32.4 |
Supplemental cash flow information: | |||
Interest paid, net of amounts capitalized | 105.2 | 103.8 | 111.6 |
Income taxes paid / (refunded), net | 0 | 0.3 | 0.8 |
Non-cash financing and investing activities: | |||
Accruals for capital expenditures | 12.9 | 16.2 | 18.6 |
Non-cash capital contribution | 97.1 | 0 | 0 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Cash flows from operating activities: | |||
Net income (loss) | 17 | (772.7) | 106.4 |
Adjustments to reconcile Net loss to Net cash from operating activities | |||
Depreciation and amortization | 87.2 | 120.3 | 138.2 |
Amortization of deferred financing costs | 1.1 | 2.9 | 2.9 |
Unrealized loss (gain) on derivatives | (1) | (4.2) | 5.7 |
Deferred income taxes | 8.1 | (477.5) | (19.2) |
Charge for early redemption of debt | 1.1 | 0.5 | 4.8 |
Fixed-asset impairment (Note 15) | 66.3 | 1,353.5 | 0 |
Loss / (Gain) on asset disposal | 15.7 | 0 | 0.4 |
Changes in certain assets and liabilities: | |||
Accounts receivable | 13.3 | (9.7) | 28.7 |
Inventories | 10.3 | 32.2 | (9.1) |
Prepaid taxes | 0 | 2.7 | (1.3) |
Taxes applicable to subsequent years | 6.4 | 0 | (3.7) |
Deferred regulatory costs, net | (23.7) | 4.1 | 21.8 |
Accounts payable | (48) | 16 | (5.8) |
Accrued taxes payable | (17.5) | (10.5) | 7.3 |
Accrued interest payable | (1.3) | (2) | (5.7) |
Pension, retiree and other benefits | 4.3 | 8.6 | (0.7) |
Unamortized investment tax credit | (1.7) | (2.3) | (2.4) |
Other | (2.2) | 2.9 | (11.6) |
Net cash provided by operating activities | 135.4 | 264.8 | 256.7 |
Cash flows from investing activities: | |||
Capital expenditures | (101.7) | (128.3) | (127) |
Insurance proceeds | 12.5 | 6.1 | 5.2 |
Purchase of renewable energy credits | (0.6) | (0.4) | (0.8) |
Decrease / (increase) in restricted cash | 26.6 | (11.9) | (0.3) |
Other investing activities, net | 0.3 | 1.1 | 0.4 |
Net cash used in investing activities | (62.9) | (133.4) | (122.5) |
Cash flows from financing activities: | |||
Dividends paid on preferred stock | 0 | (0.7) | (0.9) |
Deferred financing costs | 0 | (8.5) | (3.9) |
Preferred Stock, Redemption Amount | 0 | (23.5) | 0 |
Retirement of debt | (104.5) | (445.3) | (314.4) |
Proceeds from Contributions from Parent | 70 | 0 | 0 |
Premium paid for early redemption of debt | (0.4) | 0 | 0 |
Issuance of long-term debt | 0 | 442.8 | 200 |
Borrowings from revolving credit facilities | 40 | 0 | 50 |
Repayment of borrowings from revolving credit facilities | (30) | 0 | (50) |
Dividends paid on common stock to parent | (39) | (70) | (50) |
Borrowings from related party | 30 | 10 | 35 |
Repayment of borrowings from related party | (35) | (40) | 0 |
Net cash from financing activities | (68.9) | (135.2) | (134.2) |
Cash and cash equivalents: | |||
Net increase / (decrease) in cash | 3.6 | (3.8) | 0 |
Balance at beginning of period | 1.6 | 5.4 | 5.4 |
Cash and cash equivalents at end of period | 5.2 | 1.6 | 5.4 |
Supplemental cash flow information: | |||
Interest paid, net of amounts capitalized | 28.4 | 21.4 | 27.5 |
Income taxes paid / (refunded), net | 28.1 | 0.3 | 0.8 |
Non-cash financing and investing activities: | |||
Accruals for capital expenditures | 19.7 | 14.8 | 16.9 |
Subsidiary of Common Parent [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Non-cash financing and investing activities: | |||
Equity Settlement of Related Party Payable | $ 0 | $ 7.5 | $ 0 |
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] |
Other Comprehensive Income (Loss), Net of Tax | $ 9.9 | $ 13.6 | ||||||||
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) | 120 | ||||||||
Net loss | (239) | 106.4 | ||||||||
Common stock dividends | (50) | (50) | ||||||||
Proceeds from Contributions from Parent | 0 | |||||||||
Preferred stock dividends | (0.9) | (0.9) | ||||||||
Other | 0.3 | 0.3 | 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 | ||||||||
Non-cash capital contribution | 0 | |||||||||
Other Comprehensive Income (Loss), Net of Tax | (17.1) | (13.8) | ||||||||
Preferred Stock Redemption Premium | 5.1 | |||||||||
Net comprehensive income/ (loss) | (502.3) | (786.5) | ||||||||
Net loss | (485.2) | (772.7) | ||||||||
Common stock dividends | 70 | (70) | ||||||||
Proceeds from Contributions from Parent | 0 | |||||||||
Preferred stock dividends | (0.7) | (0.7) | ||||||||
Other | (4.7) | (4.7) | 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 | 41,172,173 | ||||||||
Non-cash capital contribution | 0 | |||||||||
Other Comprehensive Income (Loss), Net of Tax | 0.5 | 8.4 | ||||||||
Net comprehensive income/ (loss) | (94.1) | 25.4 | ||||||||
Net loss | (94.6) | 17 | ||||||||
Common stock dividends | (39) | (39) | ||||||||
Stockholders' Equity Note, Spinoff Transaction | (88.3) | |||||||||
Proceeds from Contributions from Parent | 70 | (70) | ||||||||
Other | 97.4 | 97.4 | 0.3 | (69.7) | 70 | |||||
Balance at Dec. 31, 2017 | (584.3) | $ 0 | $ 2,330.4 | $ 0.8 | $ (2,915.5) | $ 330.7 | $ 0.4 | $ 685.8 | $ (36.2) | $ (319.3) |
Balance (in shares) at Dec. 31, 2017 | 1 | |||||||||
Non-cash capital contribution | $ 97.1 |
Consolidated Statements of Sha9
Consolidated Statements of Shareholders' Equity (Parenthetical) - $ / shares | Dec. 31, 2017 | Dec. 31, 2016 |
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, 2017 | |
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 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 521,000 customers located in West Central Ohio. DP&L is required to procure and provide retail SSO electric service to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio. Since January 2016, DP&L has been sourcing 100% of the generation for its SSO customers through a competitive bid process. Through September 30, 2017, DP&L owned undivided interests in five coal-fired power stations and multiple peaking electric generating facilities as well as numerous transmission facilities. On October 1, 2017, the DP&L -owned generating facilities were transferred to AES Ohio Generation, an affiliate of DP&L and wholly-owned subsidiary of DPL , through an asset contribution agreement to a subsidiary that was merged into AES Ohio Generation. Also, Stuart Station Unit 1 was retired on October 1, 2017. 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. Through the date of Generation Separation, DP&L sold energy and capacity into the wholesale market. 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 coal-fired and 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 wholly owns each of its subsidiaries. On December 8, 2017, AES Ohio Generation completed the sale of the Miami Fort and Zimmer stations to subsidiaries of Dynegy in accordance with an asset purchase agreement dated April 21, 2017. In addition, on December 15, 2017, AES Ohio Generation entered into an asset purchase agreement for the sale of its Peaker assets to Kimura Power, LLC. 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. 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 1,060 people at January 31, 2018 , of which 660 were employed by DP&L . Approximately 60% of all DPL employees are under a collective bargaining agreement. The current agreement, after initially being extended, expired on January 31, 2018. Under national labor law, all the terms and conditions of the expired agreement continue indefinitely, with a few exceptions. Notably, the union has the right to strike and DP&L and AES Ohio Generation each have the right to lock out employees. We are continuing to negotiate with the union to enter into a new collective bargaining agreement. Currently, we are unable to predict the eventual outcome of these negotiations and have contingency plans to continue our operations. If we are not able to reach an agreement on terms favorable to us or to effectively implement our plans in the event that agreement is not reached, our results of operations, financial position and cash flows could be adversely impacted. 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. AES Ohio Generation's undivided ownership interests in certain coal-fired generating stations are included in the financial statements at amortized cost, net of subsequent impairments. Operating revenues and expenses are included on a pro rata basis in the corresponding lines in the Consolidated Statement of Operations. DP&L has undivided ownership interests in numerous transmission facilities. These undivided interests in jointly-owned facilities are accounted for on a pro rata basis in the Consolidated Financial Statements. 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. 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. 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 Consolidated 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. 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 $2.3 million , $2.8 million and $2.0 million in the years ended December 31, 2017 , 2016 and 2015 , respectively. For unregulated generation property, cost includes direct labor and material, allocable overhead expenses and interest capitalized during construction per the provisions of GAAP related 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 Impairments 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 5.0% in 2017 , 6.1% in 2016 and 4.4% in 2015 . Depreciation expense was $100.1 million , $124.6 million and $125.6 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. Regulatory Accounting As a regulated utility, DP&L applies 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, net of reserves, 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. Software is amortized over seven years. A mortization expense was $6.8 million , $7.7 million and $9.0 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. The estimated amortization expense of this internal-use software over the next five years is $17.2 million ( $7.2 million in 2018, $4.2 million in 2019, $2.7 million in 2020, $1.7 million in 2021 and $1.4 million in 2022 ). 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. Held-for-sale Businesses A business classified as held-for-sale is reflected on the balance sheet at the lower of its carrying amount or estimated fair value less cost to sell. A loss is recognized if the carrying amount of the business exceeds its estimated fair value less cost to sell. This loss is limited to the carrying value of long lived assets until the completion of the sale, at which point, any additional loss is recognized. If the fair value of the business subsequently exceeds the carrying amount while the business is still held-for-sale, any impairment expense previously recognized will be reversed up to the lower of the previously recognized expense or the subsequent excess. Assets and liabilities related to a business classified as held-for-sale are segregated in the current balance sheet in the period in which the business is classified as held-for-sale. Assets and liabilities of held-for-sale businesses are classified as current when they are expected to be disposed of within twelve months. Transactions between the business held-for-sale and businesses that are expected to continue to exist after the disposal are not eliminated to appropriately reflect the continuing operations and balances held-for-sale. See Note 17 – Assets and Liabilities Held-For-Sale and Dispositions for further information. Discontinued Operations Discontinued operations reporting occurs only when the disposal of a business or a group of businesses represents a strategic shift that has (or will have) a major effect on our operations and financial results. We report financial results for discontinued operations separately from continuing operations to distinguish the financial impact of disposal transactions from ongoing operations. Prior period amounts in the statement of operations and balance sheet are retrospectively revised to reflect the businesses determined to be discontinued operations. The cash flows of businesses that are determined to be discontinued operations are included within the relevant categories within operating, investing and financing activities on the face of the Statements of Cash Flows. Transactions between the businesses determined to be discontinued operations and businesses that are expected to continue to exist after the disposal are not eliminated to appropriately reflect the continuing operations and balances held-for-sale. The results of discontinued operations include any gain or loss recognized on closing or adjustment of the carrying amount to fair value. See Note 16 – Discontinued Operations for further information. 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, 2017 , 2016 and 2015 , were $49.4 million , $50.9 million and $49.9 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 and cash collected under the DMR which is restricted to pay debt obligations at DPL and DP&L and position DP&L to modernize and/or maintain its transmission and distribution infrastructure. 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. Insurance and Claims Costs on DPL’s Consolidated Balance Sheets associated with MVIC include estimated liabilities of approximately $3.0 million and $5.4 million at December 31, 2017 and 2016 , respectively. DPL has estimated liabilities for medical, life, disability, and other reserves for claims costs below certain coverage thresholds of third-party providers of approximately $11.9 million and $10.9 million at December 31, 2017 and 2016 , 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 DPL 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, that would otherwise be recognized in AOCI, recorded as a regulatory asset as this 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 postretirement benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postretirement 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. Consistent with the requirements of FASC 715, we apply a disaggregated discount rate approach for determining service cost and interest cost for our defined benefit pension plans and postretirement plans. 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 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. 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, 2017 and 2016 , 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, 2017 and December 31, 2016 , 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 2016-09, 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. January 1, 2017. 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. New Accounting Standards Issued But Not Yet Effective 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220), Reclassification of Certain Tax Effects from AOCI This amendment allows a reclassification of the stranded tax effects resulting from the implementation of the Tax Cuts and Jobs Act from AOCI to retained earnings. Because this amendment only relates to the reclassification of the income tax effects of the Tax Cuts and Jobs Act, the underlying guidance that requires that the effect of a change in tax laws or rates be included in income from continuing operations is not affected. January 1, 2019. Early adoption is permitted. We are currently evaluating the impact of adopting the standard on our consolidated financial statements. 2017-12, Derivatives and Hedging (Topic 815): Targeted improvements to Accounting for Hedging Activities The standard updates the hedge accounting model to expand the ability to hedge nonfinancial and financial risk components, reduce complexity, and ease certain documentation and assessment requirements. When facts and circumstances are the same as at the previous quantitative test, a subsequent quantitative effectiveness test is not required. The standard also eliminates the requirement to separately measure and report hedge ineffectiveness. For cash flow hedges, this means that the entire change in the fair value of a hedging instrument will be recorded in other comprehensive income and amounts deferred will be reclassified to earnings in the same income statement line as the hedged item. January 1, 2019. Early adoption is permitted. We are currently evaluating the impact of adopting the standard on our consolidated financial statements. 2017-08, Receivables - Nonrefundable Fees and Other Costs (Subtopic 310-20): Premium Amortization on Purchased Callable Debt Securities This standard shortens the period of amortization for the premium on certain callable debt securities to the earliest call date. January 1, 2019. Early adoption is permitted. We are currently evaluating the impact of adopting the standard on our consolidated financial statements. 2017-07, Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost This standard changes the presentation of non-service cost associated with defined benefit plans and updates the guidance so that only the service cost component will be eligible for capitalization. January 1, 2018. We expect the adoption of this standard to result in a reclassification of non-service pension costs from Operating expenses to Other expense of $1.9 million and $1.8 million in 2017 and 2016, respectively. Accounting Standard Description Date of Adoption Effect on the financial statements upon adoption 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. January 1, 2018 We expect the adoption of this standard to result in a reclassification from "Net cash used in investing activities" to "Net increase / (decrease) in cash" of $27.1 million and ($11.8) million in 2017 and 2016, respectively. 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. 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. 2016-02, Leases (Topic 842) See discussion of the ASU below. January 1, 2019. 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 ASUs below. January 1, 2018. We will adopt the standards on January 1, 2018; see below for the evaluation of the impact of its adoption on the 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 replaces most existing revenue recognition guidance in GAAP. 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. In 2016, we established a cross-functional implemen |
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 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 521,000 customers located in West Central Ohio. DP&L is required to procure and provide retail SSO electric service to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio. Since January 2016, DP&L has been sourcing 100% of the generation for its SSO customers through a competitive bid process. Through September 30, 2017, DP&L owned undivided interests in five coal-fired power stations and multiple peaking electric generating facilities as well as numerous transmission facilities. On October 1, 2017, the DP&L -owned generating facilities were transferred to AES Ohio Generation, an affiliate of DP&L , through an asset contribution agreement to a subsidiary that was merged into AES Ohio Generation. As a result of Generation Separation, DP&L now only has one reportable segment, Transmission and Distribution. In addition to DP&L's electric transmission and distribution businesses, the Transmission and Distribution segment includes revenues and costs associated with DP&L's investment in OVEC and the historical results of DP&L’s Beckjord and Hutchings Coal generating facilities, which were either closed or sold in prior periods. Principal industries located in DP&L’s service territory include automotive, food processing, paper, plastic, manufacturing and defense. DP&L's sales reflect the general economic conditions, seasonal weather patterns of the area and the market price of electricity. Through the date of Generation Separation, DP&L sold energy and capacity into the wholesale market. 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. DP&L employed 660 people at January 31, 2018 . Approximately 53% of all employees are under a collective bargaining agreement. The current agreement, after initially being extended, expired on January 31, 2018. Under national labor law, all the terms and conditions of the expired agreement continue indefinitely, with a few exceptions. Notably, the union has the right to strike and DP&L has the right to lock out employees. We are continuing to negotiate with the union to enter into a new collective bargaining agreement. Currently, we are unable to predict the eventual outcome of these negotiations and have contingency plans to continue our operations. If we are not able to reach an agreement on terms favorable to us or to effectively implement our plans in the event that agreement is not reached, our results of operations, financial position and cash flows could be adversely impacted. Financial Statement Presentation DP&L does not have any subsidiaries. DP&L has undivided ownership interests in numerous transmission facilities. These undivided interests in jointly-owned facilities are accounted for on a pro rata basis in the Financial Statements. In the fourth quarter of 2017, DP&L entered into an agreement with two other Ohio utilities to eliminate the co-ownership relationship they have had with respect to certain transmission facilities (transmission lines and substations) located in Ohio. See Note 4 – Property, Plant and Equipment for more information. 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. In 2017, we have reclassified the presentation of the December 2016 dividend payment of $70.0 million which was originally recorded as a charge to Accumulated deficit and is now presented as a charge to Other paid-in capital. This reclassification was to prospectively correct an immaterial error. 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. 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. 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-owned transmission and distribution property 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 $2.0 million , $2.7 million and $2.0 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. 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 transmission and distribution assets, straight-line depreciation is applied monthly on an average composite basis using group rates. For DP&L’s transmission and distribution assets, straight-line depreciation is applied on an average annual composite basis using group rates that approximated 3.4% in 2017 , 4.6% in 2016 and 2.5% in 2015 . Depreciation expense was $69.6 million , $64.3 million and $64.3 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. Regulatory Accounting As a regulated utility, DP&L applies 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 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. Software is amortized over seven years. A mortization expense was $5.7 million , $6.7 million and $7.2 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. The estimated amortization expense of this internal-use software over the next five years is $10.7 million ( $5.1 million in 2018, $3.1 million in 2019, $1.6 million in 2020, $0.6 million in 2021 and $0.3 million in 2022 ). 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. DP&L files 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. Held-for-sale Businesses A business classified as held-for-sale is reflected on the balance sheet at the lower of its carrying amount or estimated fair value less cost to sell. A loss is recognized if the carrying amount of the business exceeds its estimated fair value less cost to sell. This loss is limited to the carrying value of long lived assets until the completion of the sale, at which point, any additional loss is recognized. If the fair value of the business subsequently exceeds the carrying amount while the business is still held-for-sale, any impairment expense previously recognized will be reversed up to the lower of the previously recognized expense or the subsequent excess. Assets and liabilities related to a business classified as held-for-sale are segregated in the current balance sheet in the period in which the business is classified as held-for-sale. Assets and liabilities of held-for-sale businesses are classified as current when they are expected to be disposed of within twelve months. Transactions between the business held-for-sale and businesses that are expected to continue to exist after the disposal are not eliminated to appropriately reflect the continuing operations and balances held-for-sale. See Note 13 – Generation Separation for further information. Discontinued Operations Discontinued operations reporting occurs only when the disposal of a business or a group of businesses represents a strategic shift that has (or will have) a major effect on our operations and financial results. We report financial results for discontinued operations separately from continuing operations to distinguish the financial impact of disposal transactions from ongoing operations. Prior period amounts in the statement of operations and balance sheet are retrospectively revised to reflect the businesses determined to be discontinued operations. The cash flows of businesses that are determined to be discontinued operations are included within the relevant categories within operating, investing and financing activities on the face of the Statements of Cash Flows. Transactions between the businesses determined to be discontinued operations and businesses that are expected to continue to exist after the disposal are not eliminated to appropriately reflect the continuing operations and balances held-for-sale. The results of discontinued operations include any gain or loss recognized on closing or adjustment of the carrying amount to fair value. See Note 13 – Generation Separation for further information. Generation Separation With the transfer of DP&L's generation assets to an affiliate (see Note 13 – Generation Separation ), DP&L's generation business is presented as a discontinued operation and the operating activities have been reclassified to "Discontinued operations" in the Statements of Operations for the years ended December 31, 2017, 2016 and 2015 and in the footnotes to the financial statements. The assets and liabilities related to the discontinued operations have been reclassified to held-for-sale in the balance sheet as of December 31, 2016. 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, 2017 , 2016 and 2015 were $49.4 million , $50.9 million and $49.9 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 relates to cash collected under the DMR which is restricted to pay debt obligations at DPL and DP&L and position DP&L to modernize and/or maintain its transmission and distribution infrastructure. 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. We use forward contracts to reduce our exposure to changes in interest rates. 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 $4.4 million and $3.9 million at December 31, 2017 and 2016 , 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, that would otherwise be recognized in AOCI, recorded as a regulatory asset as this 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 postretirement benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postretirement 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. Consistent with the requirements of FASC 715, we apply a disaggregated discount rate approach for determining service cost and interest cost for our defined benefit pension plans and postretirement plans. 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 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. 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 2016-09, 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. January 1, 2017. 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. New Accounting Standards Issued But Not Yet Effective 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220), Reclassification of Certain Tax Effects from AOCI This amendment allows a reclassification of the stranded tax effects resulting from the implementation of the Tax Cuts and Jobs Act from AOCI to retained earnings. Because this amendment only relates to the reclassification of the income tax effects of the Tax Cuts and Jobs Act, the underlying guidance that requires that the effect of a change in tax laws or rates be included in income from continuing operations is not affected. January 1, 2019. Early adoption is permitted. We are currently evaluating the impact of adopting the standard on our financial statements. 2017-12, Derivatives and Hedging (Topic 815): Targeted improvements to Accounting for Hedging Activities The standard updates the hedge accounting model to expand the ability to hedge nonfinancial and financial risk components, reduce complexity, and ease certain documentation and assessment requirements. When facts and circumstances are the same as at the previous quantitative test, a subsequent quantitative effectiveness test is not required. The standard also eliminates the requirement to separately measure and report hedge ineffectiveness. For cash flow hedges, this means that the entire change in the fair value of a hedging instrument will be recorded in other comprehensive income and amounts deferred will be reclassified to earnings in the same income statement line as the hedged item. January 1, 2019. Early adoption is permitted. We are currently evaluating the impact of adopting the standard on our financial statements. 2017-08, Receivables - Nonrefundable Fees and Other Costs (Subtopic 310-20): Premium Amortization on Purchased Callable Debt Securities This standard shortens the period of amortization for the premium on certain callable debt securities to the earliest call date. January 1, 2019. Early adoption is permitted. We are currently evaluating the impact of adopting the standard on our financial statements. 2017-07, Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost This standard changes the presentation of non-service cost associated with defined benefit plans and updates the guidance so that only the service cost component will be eligible for capitalization. January 1, 2018. We expect the adoption of this standard to result in a reclassification of non-service pension costs from Operating expenses to Other expense of $7.2 million and $7.8 million in 2017 and 2016, respectively. 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. January 1, 2018 We expect the adoption of this standard to result in a reclassification from "Net cash used in investing activities" to "Net increase / (decrease) in cash" of $26.6 million and ($11.9) million in 2017 and 2016, respectively. Accounting Standard Description Date of Adoption Effect on the financial statements upon adoption 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. 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. 2016-02, Leases (Topic 842) See discussion of the ASU below. January 1, 2019. 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 ASUs below. January 1, 2018. We will adopt the standards on January 1, 2018; see below for the evaluation of the impact of its adoption on the 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 replaces most existing revenue recognition guidance in GAAP. 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. 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. At this time, we do not expect any significant impact on our financial systems or a material change to controls as a result of the implementation of the new revenue recognition standard. We are assessing the standard on a contract-by-contract basis applying the interpretations reached during 2017 on key issues. This includes the application of the practical expedient for measuring progress towards 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 allocate variable consideration to one or more, but not all, distinct goods or services promised in a series of distinct goods or services that forms part of a single performance obligation. Additionally, we have been working on the application of the standard to contracts that are under the scope of Service Concession Arrangements (Topic 853) and assessing the gross versus net presentation for spot energy sale and purchases. Through this assessment to date, we have not identified any situations where revenue recognized under FASC 606 could differ from that recognized under FASC 605 or where the presentation of sales to and purchases from the spot markets will change. Given the limited impact, we expect to use the modified retrospective approach. We are continuing to work with various non-authoritative industry groups and continue to monitor the FASB and Transition Resource Group activity as we finalize our accounting policy on these and other industry-specific interpretive issues. ASU 2016-02 and its subsequent corresponding updates require lessees to recognize assets and liabilities for most leases but recognize expenses in a manner similar to today’s accounting. For Lessors, the guidance modifies the lease classification criteria and the accounting for sales-type and direct financing leases. The guidance also eliminates today’s real estate-specific provisions. The standard requires modified retrospective adoption at the beginning of the earliest comparative period presented in the financial statements (January 1, 2017). The FASB proposed amending the standard to give another option for transition. The proposed transition method would allow entities to not apply the new lease standard in the comparative periods presented in their financial statements in the year of adoption. Under the proposed transition method, the entity would apply the transition provisions on January 1, 2019 (i.e., the effective date). At transition, lessees and lessors are permitted to make an election to apply a package of practical expedients that allow them not to reassess: (1) whether any expired or existing contracts are or contain leases, (2) lease classification for any expired or existing leases, and (3) whether initial direct costs for any expired or existing leases qualify for capitalization under FASC 842. These three practical expedients must be elected as a |
Supplemental Financial Informat
Supplemental Financial Information | 12 Months Ended |
Dec. 31, 2017 | |
Supplemental Financial Information [Line Items] | |
Additional Financial Information Disclosure [Text Block] | Supplemental Financial Information December 31, $ in millions 2017 2016 Accounts receivable, net Unbilled revenue $ 18.0 $ 43.0 Customer receivables 57.8 73.9 Amounts due from partners in jointly-owned stations 19.1 12.7 Other 4.9 6.7 Provisions for uncollectible accounts (1.1 ) (1.2 ) Total accounts receivable, net $ 98.7 $ 135.1 Inventories, at average cost Fuel and limestone $ 15.5 $ 38.9 Plant materials and supplies 8.5 36.6 Other 0.5 1.7 Total inventories, at average cost $ 24.5 $ 77.2 Accumulated Other Comprehensive Income / (Loss) The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the years ended December 31, 2017 , 2016 and 2015 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 2017 2016 2015 Gains and losses on Available-for-sale securities activity (Note 5): Other deductions $ (0.1 ) $ — $ — Income tax expense / (benefit) from continuing operations — — — Net of income taxes (0.1 ) — — Gains and losses on cash flow hedges (Note 6): Interest expense (1.0 ) (1.0 ) (1.1 ) Revenues (15.2 ) (55.3 ) (18.7 ) Net purchased power cost 3.8 9.9 4.4 Total before income taxes (12.4 ) (46.4 ) (15.4 ) Income tax expense / (benefit) from continuing operations 4.4 16.7 5.4 Net of income taxes (8.0 ) (29.7 ) (10.0 ) Amortization of defined benefit pension items (Note 10): Operation and maintenance 1.5 1.6 0.4 Income tax expense / (benefit) from continuing operations (0.5 ) (0.6 ) (0.2 ) Net of income taxes 1.0 1.0 0.2 Total reclassifications for the period, net of income taxes $ (7.1 ) $ (28.7 ) $ (9.8 ) The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the years ended December 31, 2017 and 2016 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, 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 Other comprehensive income / (loss) before reclassifications 0.5 9.6 (2.5 ) 7.6 Amounts reclassified from accumulated other comprehensive income / (loss) (0.1 ) (8.0 ) 1.0 (7.1 ) Net current period other comprehensive income / (loss) 0.4 1.6 (1.5 ) 0.5 Balance at December 31, 2017 $ 1.0 $ 14.7 $ (14.9 ) $ 0.8 Operating expenses - other Operating expenses - other generally includes gains or losses on asset sales or dispositions, insurance recoveries, gains or losses on the sale of businesses and other expense or income from miscellaneous transactions. The components are summarized as follows: Years ended December 31, $ in millions 2017 2016 2015 Write-off of plant materials and supplies inventories $ 16.2 $ — $ — Gain on sale of business (14.0 ) — — Insurance recoveries (8.7 ) (0.7 ) — Loss / (gain) on disposition of property — (0.1 ) 0.4 Other (0.1 ) 0.7 — Net other expense / (income) $ (6.6 ) $ (0.1 ) $ 0.4 |
Supplemental Financial Information | December 31, $ in millions 2017 2016 Accounts receivable, net Unbilled revenue $ 18.0 $ 43.0 Customer receivables 57.8 73.9 Amounts due from partners in jointly-owned stations 19.1 12.7 Other 4.9 6.7 Provisions for uncollectible accounts (1.1 ) (1.2 ) Total accounts receivable, net $ 98.7 $ 135.1 Inventories, at average cost Fuel and limestone $ 15.5 $ 38.9 Plant materials and supplies 8.5 36.6 Other 0.5 1.7 Total inventories, at average cost $ 24.5 $ 77.2 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Supplemental Financial Information [Line Items] | |
Additional Financial Information Disclosure [Text Block] | Supplemental Financial Information December 31, $ in millions 2017 2016 Accounts receivable, net Unbilled revenue $ 18.0 $ 43.0 Customer receivables 44.2 45.9 Amounts due from partners in jointly-owned stations 5.0 4.0 Other 4.7 8.1 Provisions for uncollectible accounts (1.1 ) (1.2 ) Total accounts receivable, net $ 70.8 $ 99.8 Inventories, at average cost Plant materials and supplies $ 6.9 $ 6.9 Other 0.4 2.4 Total inventories, at average cost $ 7.3 $ 9.3 Accumulated Other Comprehensive Income (Loss) The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the years ended December 31, 2017 , 2016 and 2015 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 2017 2016 2015 Gains and losses on Available-for-sale securities activity (Note 5): Other deductions $ (0.1 ) $ — $ — Income tax expense from continuing operations — — — Net of income taxes (0.1 ) — — Gains and losses on cash flow hedges (Note 6): Interest expense (0.9 ) (1.0 ) (1.1 ) Income tax expense from continuing operations 0.2 0.2 0.2 Loss from discontinued operations (8.5 ) (45.4 ) (14.3 ) Income tax benefit from discontinued operations 3.0 16.2 5.4 Net of income taxes (6.2 ) (30.0 ) (9.8 ) Amortization of defined benefit pension items (Note 9): Operation and maintenance 6.8 7.7 5.6 Income tax expense from continuing operations (2.3 ) (1.8 ) (1.9 ) Net of income taxes 4.5 5.9 3.7 Total reclassifications for the period, net of income taxes $ (1.8 ) $ (24.1 ) $ (6.1 ) The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the years ended December 31, 2017 and 2016 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, 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 ) Other comprehensive income / (loss) before reclassifications 0.5 12.4 (2.7 ) 10.2 Amounts reclassified from accumulated other comprehensive income / (loss) (0.1 ) (6.2 ) 4.5 (1.8 ) Net current period other comprehensive income 0.4 6.2 1.8 8.4 Transfer of generation assets to subsidiary of parent — (2.1 ) — (2.1 ) Balance at December 31, 2017 $ 1.1 $ 1.4 $ (38.7 ) $ (36.2 ) |
Supplemental Financial Information | Supplemental Financial Information December 31, $ in millions 2017 2016 Accounts receivable, net Unbilled revenue $ 18.0 $ 43.0 Customer receivables 44.2 45.9 Amounts due from partners in jointly-owned stations 5.0 4.0 Other 4.7 8.1 Provisions for uncollectible accounts (1.1 ) (1.2 ) Total accounts receivable, net $ 70.8 $ 99.8 Inventories, at average cost Plant materials and supplies $ 6.9 $ 6.9 Other 0.4 2.4 Total inventories, at average cost $ 7.3 $ 9.3 |
Regulatory Assets and Liabiliti
Regulatory Assets and Liabilities | 12 Months Ended |
Dec. 31, 2017 | |
Regulatory Assets [Line Items] | |
Regulatory Assets and Liabilities | Regulatory Matters In January 2017, DP&L filed a settlement in its 2017 ESP case and filed an amended stipulation on March 13, 2017, which was subject to approval by the PUCO. A final decision was issued by the PUCO on October 20, 2017, modifying and adopting the amended stipulation and recommendation. The 2017 ESP establishes DP&L's framework for providing retail service on a going forward basis including rate structures, non-bypassable charges and other specific rate recovery true-up mechanisms. The signatory 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: • Bypassable standard offer energy rates for DP&L’s customers based on competitive bid auctions; • The establishment of a three -year non-bypassable Distribution Modernization Rider (DMR) designed to collect $105.0 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 with an option for DP&L to file for an extension of the rider for an additional two years in an amount subject to approval by the PUCO; • The establishment of a non-bypassable Distribution Investment Rider to recover incremental distribution capital investments, the amount of which is to be established in a separate DP&L distribution rate case; • A non-bypassable Reconciliation Rider permitting DP&L to defer, recover or credit the net proceeds from selling energy and capacity received as part of DP&L’s investment in OVEC and DP&L's OVEC related costs; • Implementation by DP&L of a Smart Grid Rider, Economic Development Rider, Economic Development Fund, Regulatory Compliance Rider and certain other new, or changes to existing, rates, riders and competitive retail market enhancements, with tariffs consistent with the order. These riders became effective November 1, 2017; • A commitment to commence a sale process to sell our ownership interests in the Miami Fort, Zimmer and Conesville coal-fired generation plants, with all sales proceeds used to pay debt of DPL and DP&L; • Restrictions on DPL making dividend or tax sharing payments and an obligation to convert then existing tax payments owed by DPL to AES into equity investments in DPL . See Note 9 – Income Taxes and Note 11 – Equity for more information on the tax sharing payment restrictions; and • Various other riders and competitive retail market enhancements. In connection with any sale or closure of our generation plants, DPL expects to incur certain cash and non-cash charges, some or all of which could be material to the business and financial condition of DPL . As part of the normal review and approval process, the PUCO‘s order approving the 2017 ESP settlement is subject to rehearing requests. Several parties, including DP&L , applied for a rehearing. Those rehearing applications are still pending. DP&L is subject to a SEET threshold and is required to apply general rules for calculating earnings and comparing them to a comparable group to determine whether there were significantly excessive earnings during a given calendar year. The 2017 ESP maintains DP&L’s return on equity SEET threshold at 12% and provides that DMR amounts are excluded from the SEET calculation. A stipulation was reached with the PUCO staff agreeing that DP&L did not exceed the SEET threshold for 2015, which was approved by the PUCO on September 6, 2017. On May 15, 2017, DP&L filed its application to demonstrate that it did not have significantly excessive earnings for calendar year 2016. That case is still pending. In future years, the SEET could have a material effect on results of operations, financial condition and cash flows. The DOE issued a Notice of Proposed Rule Making on September 29, 2017, which directed the FERC to exercise its authority to set just and reasonable rates that recognize the “resiliency” value provided by generation plants with certain characteristics, including having 90-days or more of on-site fuel and operating in markets where they do not receive rate base treatment through state ratemaking. Nuclear and coal-fired generation plants would have been most likely to be able to meet the requirements. As proposed, the DOE would value resiliency through rates that recover “compensable costs” that were defined to include the recovery of operating and fuel expenses, debt service and a fair return on equity. On January 8, 2018, the FERC issued an order terminating this docket stating that it failed to satisfy the legal requirements of Section 206 of the Federal Power Act of 1935. The FERC initiated a new docket to take additional steps to explore resilience issues in RTOs/ISOs. The goal of this new proceeding is to: (1) develop a common understanding among the FERC, State Commissions, RTOs, transmission owners, and others as to what resilience of the bulk power system means and requires; (2) understand how each RTO and ISO assesses resilience in its geographic footprint; and (3) use this information to evaluate whether additional action regarding resilience is appropriate at this time. We are not able at this time to predict the impact of this proceeding on our business, financial condition or results of operations. Impact of tax reform On January 10, 2018 the PUCO initiated a proceeding to consider the impacts of the TCJA to determine the appropriate course of action to pass benefits resulting from the legislation on to ratepayers. The PUCO also directed Ohio utilities to record deferred liabilities for the estimated reduction in federal income tax resulting from the TCJA beginning January 1, 2018. Under the terms of the ESP, DPL will not make tax sharing payments and if DP&L's rates are reduced as a result of the TCJA, our cash flows could be adversely affected. It is too early to determine whether this proceeding may have a material impact on DP&L's business, financial condition or results of operations. Regulatory assets and liabilities In accordance with FASC 980, we have recognized total regulatory assets of $187.1 million and $204.0 million at December 31, 2017 and 2016 , respectively, and total regulatory liabilities of $236.0 million and $164.1 million at December 31, 2017 and 2016 , 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: Type of Recovery Amortization Through December 31, $ in millions 2017 2016 Regulatory assets, current: Undercollections to be collected through rate riders A/B 2018 $ 23.9 $ 0.1 Total regulatory assets, current 23.9 0.1 Regulatory assets, non-current: Pension benefits B Ongoing 92.4 97.6 Deferred recoverable income taxes B/C Ongoing — 35.9 Unrecovered OVEC charges D Undetermined 27.8 21.0 Fuel costs B 2020 9.3 15.4 Regulatory compliance costs B 2020 9.2 12.4 Rate case costs B Undetermined 8.1 6.3 Smart grid and AMI costs B Undetermined 7.3 7.3 Unamortized loss on reacquired debt B Various 7.0 8.0 Deferred storm costs A Undetermined 2.1 — Total regulatory assets, non-current 163.2 203.9 Total regulatory assets $ 187.1 $ 204.0 Regulatory liabilities, current: Overcollection of costs to be refunded through rate riders A/B 2018 $ 14.8 $ 33.7 Total regulatory liabilities, current 14.8 33.7 Regulatory liabilities, non-current: Estimated costs of removal - regulated property Not Applicable 132.8 126.5 Deferred income taxes payable through rates Various 83.4 — Postretirement benefits B Ongoing 5.0 3.9 Total regulatory liabilities, non-current 221.2 130.4 Total regulatory liabilities $ 236.0 $ 164.1 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 recovery is probable of occurring in future rate proceedings. Current regulatory assets and liabilities primarily represent costs that are being recovered per specific rate order; recovery for the remaining costs is probable, but not certain. DP&L is earning a return on $12.5 million of this deferral. These items include undercollection of: (i) Distribution Modernization Rider revenues, (ii) certain transmission related costs, and (iii) declines in net revenues resulting from implementation of energy efficiency programs. It also includes the current portion of the following deferred costs which are described in greater detail below: unbilled fuel, Regulatory Compliance Rider costs and deferred storm costs. As current liabilities, this includes overcollection of: (i) competitive bidding energy and auction costs, (ii) energy efficiency program costs, (iii) alternative energy rider, (iv) economic development rider and (v) uncollectible rider. 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. As per PUCO and FERC precedents, these costs are probable of future rate recovery. Unrecovered OVEC charges includes the portion of charges from OVEC that were not recoverable through DP&L’s fuel rider from October 2014 through October 2017. DP&L expects to recover these costs through a future rate proceeding. Beginning on November 1, 2017, such costs are being recovered through DP&L’s Reconciliation Rider which was authorized as part of the 2017 ESP. Fuel costs represent unrecovered fuel costs related to DP&L’s fuel rider from 2010 through 2015 resulting from a declining SSO customer base. DP&L was granted recovery of these costs without a return through the SSO as approved in the 2017 ESP. These costs are being recovered over the three-year period that began November 1, 2017. Regulatory compliance costs represent the long-term portion of the regulatory compliance rider which was established by the 2017 ESP to recover the following costs: (i) Consumer Education Campaign, (ii) Retail Settlement System, (iii) Generation Separation, (iv) Bill Format Redesign, (v) Green Pricing Tariff and (vi) Supplier Consolidated Billing. All of these costs except for Generation Separation earn a return. The majority of these costs are being recovered over the three-years beginning November 1, 2017. Recovery of a small portion of the Generation Separation costs, including ongoing costs, will be sought in a future proceeding. Rate case costs represents costs associated with preparing a distribution rate case and ESP. DP&L has requested recovery of these costs which do not earn a return, as part of its pending distribution rate case filing. Smart Grid and AMI costs represent costs incurred as a result of studying and developing distribution system upgrades and 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 recovery of these deferred costs, which currently do not earn a return, in a regulatory rate proceeding in the near future. Based on PUCO precedent, we believe these costs are probable of future recovery in rates. 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 the rules of the FERC and the PUCO. Deferred storm costs represent the long-term portion of deferred costs for major storms which occurred during 2016 and 2017. The 2017 ESP granted DP&L approval to establish a rider by which to seek recovery of these types of costs with a return. DP&L filed to recover 2016 storm costs on February 2, 2018 and expects to file to recover 2017 costs later in 2018. Recovery of these costs is probable by 2019, but not certain. 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. Deferred income taxes payable to customers represent deferred income tax assets recognized from the normalization of flow-through items as the result of taxes previously charged to customers. A deferred income tax asset or liability is created from a difference in income recognition between tax laws and accounting methods. As a regulated utility, DP&L includes in ratemaking the impacts of current income taxes and changes in deferred income tax liabilities or assets. The 2016 regulatory asset of $35.9 million represents the portion of DP&L’s deferred income tax asset that we believed would be recovered through future rates, without interest, based upon established regulatory practices. That 2016 asset was based upon an expected future federal income tax rate of 35% . On December 22, 2017, the TCJA was signed, which includes a provision to, among other things, reduce the federal corporate income tax rate to 21% , beginning January 1, 2018. As required by GAAP, on December 31, 2017, DP&L remeasured their deferred income tax assets and liabilities using the new expected tax rate. DP&L believes that the portion of the reduction in the net deferred tax liability which is related to deferred taxes considered in ratemaking will be used in future ratemaking to reduce jurisdictional retail rates. Accordingly, the related regulatory asset became a $83.4 million regulatory liability. 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 In January 2017, DP&L filed a settlement in its 2017 ESP case and filed an amended stipulation on March 13, 2017, which was subject to approval by the PUCO. A final decision was issued by the PUCO on October 20, 2017, modifying and adopting the amended stipulation and recommendation. The 2017 ESP establishes DP&L's framework for providing retail service on a going forward basis including rate structures, non-bypassable charges and other specific rate recovery true-up mechanisms. The signatory 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: • Bypassable standard offer energy rates for DP&L’s customers based on competitive bid auctions; • The establishment of a three -year non-bypassable Distribution Modernization Rider (DMR) designed to collect $105.0 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 with an option for DP&L to file for an extension of the rider for an additional two years in an amount subject to approval by the PUCO; • The establishment of a non-bypassable Distribution Investment Rider to recover incremental distribution capital investments, the amount of which is to be established in a separate DP&L distribution rate case; • A non-bypassable Reconciliation Rider permitting DP&L to defer, recover or credit the net proceeds from selling energy and capacity received as part of DP&L’s investment in OVEC and DP&L's OVEC related costs; • Implementation by DP&L of a Smart Grid Rider, Economic Development Rider, Economic Development Fund, Regulatory Compliance Rider and certain other new, or changes to existing, rates, riders and competitive retail market enhancements, with tariffs consistent with the order. These riders became effective November 1, 2017; • A commitment to commence a sale process to sell our ownership interests in the Miami Fort, Zimmer and Conesville coal-fired generation plants, with all sales proceeds used to pay debt of DPL and DP&L; • Restrictions on DPL making dividend or tax sharing payments and an obligation to convert then existing tax payments owed by DPL to AES into equity investments in DPL ; • Various other riders and competitive retail market enhancements. As part of the normal review and approval process, the PUCO‘s order approving the 2017 ESP settlement is subject to rehearing requests. Several parties, including DP&L , applied for a rehearing. Those rehearing applications are still pending. DP&L is subject to a SEET threshold and is required to apply general rules for calculating earnings and comparing them to a comparable group to determine whether there were significantly excessive earnings during a given calendar year. The 2017 ESP maintains DP&L’s return on equity SEET threshold at 12% and provides that DMR amounts are excluded from the SEET calculation. A stipulation was reached with the PUCO staff agreeing that DP&L did not exceed the SEET threshold for 2015, which was approved by the PUCO on September 6, 2017. On May 15, 2017, DP&L filed its application to demonstrate that it did not have significantly excessive earnings for calendar year 2016. That case is still pending. In future years, the SEET could have a material effect on results of operations, financial condition and cash flows. The DOE issued a Notice of Proposed Rule Making on September 29, 2017, which directed the FERC to exercise its authority to set just and reasonable rates that recognize the “resiliency” value provided by generation plants with certain characteristics, including having 90-days or more of on-site fuel and operating in markets where they do not receive rate base treatment through state ratemaking. Nuclear and coal-fired generation plants would have been most likely to be able to meet the requirements. As proposed, the DOE would value resiliency through rates that recover “compensable costs” that were defined to include the recovery of operating and fuel expenses, debt service and a fair return on equity. On January 8, 2018, the FERC issued an order terminating this docket stating that it failed to satisfy the legal requirements of Section 206 of the Federal Power Act of 1935. The FERC initiated a new docket to take additional steps to explore resilience issues in RTOs/ISOs. The goal of this new proceeding is to: (1) develop a common understanding among the FERC, State Commissions, RTOs, transmission owners, and others as to what resilience of the bulk power system means and requires; (2) understand how each RTO and ISO assesses resilience in its geographic footprint; and (3) use this information to evaluate whether additional action regarding resilience is appropriate at this time. We are not able at this time to predict the impact of this proceeding on our business, financial condition or results of operations. Impact of tax reform On January 10, 2018 the PUCO initiated a proceeding to consider the impacts of the TCJA to determine the appropriate course of action to pass benefits resulting from the legislation on to ratepayers. The PUCO also directed Ohio utilities to record deferred liabilities for the estimated reduction in federal income tax resulting from the TCJA beginning January 1, 2018. Under the terms of the ESP, DPL will not make tax sharing payments and if DP&L's rates are reduced as a result of the TCJA, our cash flows could be adversely affected. It is too early to determine whether this proceeding may have a material impact on DP&L's business, financial condition or results of operations. Regulatory assets and liabilities In accordance with FASC 980, we have recognized total regulatory assets of $187.1 million and $204.0 million at December 31, 2017 and 2016 , respectively, and total regulatory liabilities of $236.0 million and $164.1 million at December 31, 2017 and 2016 , 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: Type of Recovery Amortization Through December 31, $ in millions 2017 2016 Regulatory assets, current: Undercollections to be collected through rate riders A/B 2018 $ 23.9 $ 0.1 Total regulatory assets, current 23.9 0.1 Regulatory assets, non-current: Pension benefits B Ongoing 92.4 97.6 Deferred recoverable income taxes B/C Ongoing — 35.9 Unrecovered OVEC charges D Undetermined 27.8 21.0 Fuel costs B 2020 9.3 15.4 Regulatory compliance costs B 2020 9.2 12.4 Rate case costs B Undetermined 8.1 6.3 Smart grid and AMI costs B Undetermined 7.3 7.3 Unamortized loss on reacquired debt B Various 7.0 8.0 Deferred storm costs A Undetermined 2.1 — Total regulatory assets, non-current 163.2 203.9 Total regulatory assets $ 187.1 $ 204.0 Regulatory liabilities, current: Overcollection of costs to be refunded through rate riders A/B 2018 $ 14.8 $ 33.7 Total regulatory liabilities, current 14.8 33.7 Regulatory liabilities, non-current: Estimated costs of removal - regulated property Not Applicable 132.8 126.5 Deferred income taxes payable through rates Various 83.4 — Postretirement benefits B Ongoing 5.0 3.9 Total regulatory liabilities, non-current 221.2 130.4 Total regulatory liabilities $ 236.0 $ 164.1 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 recovery is probable of occurring in future rate proceedings. Current regulatory assets and liabilities primarily represent costs that are being recovered per specific rate order; recovery for the remaining costs is probable, but not certain. DP&L is earning a return on $12.5 million of this deferral. These items include undercollection of: (i) Distribution Modernization Rider revenues, (ii) certain transmission related costs, and (iii) declines in net revenues resulting from implementation of energy efficiency programs. It also includes the current portion of the following deferred costs which are described in greater detail below: unbilled fuel, Regulatory Compliance Rider costs and deferred storm costs. As current liabilities, this includes overcollection of: (i) competitive bidding energy and auction costs, (ii) energy efficiency program costs, (iii) alternative energy rider, (iv) economic development rider and (v) uncollectible rider. 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. As per PUCO and FERC precedents, these costs are probable of future rate recovery. Unrecovered OVEC charges includes the portion of charges from OVEC that were not recoverable through DP&L’s fuel rider from October 2014 through October 2017. DP&L expects to recover these costs through a future rate proceeding. Beginning on November 1, 2017, such costs are being recovered through DP&L’s Reconciliation Rider which was authorized as part of the 2017 ESP. Fuel costs represent unrecovered fuel costs related to DP&L’s fuel rider from 2010 through 2015 resulting from a declining SSO customer base. DP&L was granted recovery of these costs without a return through the SSO as approved in the 2017 ESP. These costs are being recovered over the three-year period that began November 1, 2017. Regulatory compliance costs represent the long-term portion of the regulatory compliance rider which was established by the 2017 ESP to recover the following costs: (i) Consumer Education Campaign, (ii) Retail Settlement System, (iii) Generation Separation, (iv) Bill Format Redesign, (v) Green Pricing Tariff and (vi) Supplier Consolidated Billing. All of these costs except for Generation Separation earn a return. The majority of these costs are being recovered over the three-years beginning November 1, 2017. Recovery of a small portion of the Generation Separation costs, including ongoing costs, will be sought in a future proceeding. Rate case costs represents costs associated with preparing a distribution rate case and ESP. DP&L has requested recovery of these costs which do not earn a return, as part of its pending distribution rate case filing. Smart Grid and AMI costs represent costs incurred as a result of studying and developing distribution system upgrades and 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 recovery of these deferred costs, which currently do not earn a return, in a regulatory rate proceeding in the near future. Based on PUCO precedent, we believe these costs are probable of future recovery in rates. 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 the rules of the FERC and the PUCO. Deferred storm costs represent the long-term portion of deferred costs for major storms which occurred during 2016 and 2017. The 2017 ESP granted DP&L approval to establish a rider by which to seek recovery of these types of costs with a return. DP&L filed to recover 2016 storm costs on February 2, 2018 and expects to file to recover 2017 costs later in 2018. Recovery of these costs is probable by 2019, but not certain. 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. Deferred income taxes payable to customers represent deferred income tax assets recognized from the normalization of flow-through items as the result of taxes previously charged to customers. A deferred income tax asset or liability is created from a difference in income recognition between tax laws and accounting methods. As a regulated utility, DP&L includes in ratemaking the impacts of current income taxes and changes in deferred income tax liabilities or assets. The 2016 regulatory asset of $35.9 million represents the portion of DP&L’s deferred income tax asset that we believed would be recovered through future rates, without interest, based upon established regulatory practices. That 2016 asset was based upon an expected future federal income tax rate of 35% . On December 22, 2017, the TCJA was signed, which includes a provision to, among other things, reduce the federal corporate income tax rate to 21% , beginning January 1, 2018. As required by GAAP, on December 31, 2017, DP&L remeasured their deferred income tax assets and liabilities using the new expected tax rate. DP&L believes that the portion of the reduction in the net deferred tax liability which is related to deferred taxes considered in ratemaking will be used in future ratemaking to reduce jurisdictional retail rates. Accordingly, the related regulatory asset became a 83.4 million regulatory liability. 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, 2017 | |
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, 2017 and 2016 : December 31, 2017 December 31, 2016 $ in millions Composite Rate Composite Rate Regulated: Transmission $ 242.7 4.0% $ 247.3 3.9% Distribution 1,197.5 4.9% 1,141.1 4.7% General 13.7 7.1% 13.7 7.4% Non-depreciable 64.7 N/A 63.5 N/A Total regulated 1,518.6 1,465.6 Unregulated: Production / Generation 10.9 63.2% 483.2 11.7% Other 19.4 7.0% 17.0 8.0% Non-depreciable 5.8 N/A 19.8 N/A Total unregulated 36.1 520.0 Total property, plant and equipment in service $ 1,554.7 5.0% $ 1,985.6 6.1% Coal-fired facilities DPL and certain other Ohio utilities have undivided ownership interests in three 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. DPL’s share of the operations of such facilities is included within the corresponding line in the Consolidated Statements of Operations, and DPL’s share of the investment in the facilities is included within Total net property, plant and equipment in the Consolidated Balance Sheets. Each joint owner provides their own financing for their share of the operations and capital expenditures of the jointly-owned station. DPL’s undivided ownership interest in such facilities at December 31, 2017 , is as follows: DPL 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 $ 0.7 $ 0.7 $ 1.9 Killen - Unit 2 67.0 402 9.6 8.2 — Stuart - Units 2 through 4 35.0 606 1.8 1.8 — Transmission (at varying percentages) 45.6 13.3 — Total 1,137 $ 57.7 $ 24.0 $ 1.9 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. The unit was retired on October 1, 2017. Accordingly, DPL's 202 MWs of capacity associated with Stuart Unit 1 have been removed from the table above. DPL announced during 2017 that it plans on retiring the co-owned Stuart Station coal-fired and diesel-fired generating units and the co-owned Killen Station coal-fired generating unit and combustion turbine on or before June 1, 2018, and the co-owners of these facilities agreed with this plan of retirement. On December 8, 2017, AES Ohio Generation completed the sale of the Miami Fort and Zimmer EGUs. In the fourth quarter of 2017, DPL entered into an agreement to sell its Peaker assets. See Note 17 – Assets and Liabilities Held-For-Sale and Dispositions for more information. 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, 2015 $ 65.9 Calendar 2016 Additions 70.2 Accretion expense 2.7 Settlements — Balance at December 31, 2016 138.8 Calendar 2017 Additions 0.1 Revisions to cash flow and timing estimates (6.3 ) Accretion expense 3.7 Settlements (0.1 ) Reductions due to plants sold or held-for-sale (5.0 ) Balance at December 31, 2017 $ 131.2 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 $132.8 million and $126.5 million in estimated costs of removal at December 31, 2017 and 2016 , 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, 2015 $ 121.8 Calendar 2016 Additions 11.7 Settlements (7.0 ) Balance at December 31, 2016 126.5 Calendar 2017 Additions 12.0 Settlements (5.7 ) Balance at December 31, 2017 $ 132.8 |
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, 2017 and 2016 : December 31, 2017 December 31, 2016 $ in millions Composite Rate Composite Rate Regulated: Transmission $ 414.6 2.4% $ 421.1 2.3% Distribution 1,735.9 3.4% 1,693.5 3.2% General 31.2 3.1% 31.6 3.2% Non-depreciable 64.6 N/A 63.5 N/A Total regulated 2,246.3 2,209.7 Unregulated: Other 0.2 2.7% 0.3 2.7% Non-depreciable 0.7 N/A 3.5 N/A Total unregulated 0.9 3.8 Total property, plant and equipment in service $ 2,247.2 3.4% $ 2,213.5 4.6% 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. 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, 2015 $ 5.0 Calendar 2016 Additions 2.7 Accretion expense 0.3 Settlements 0.2 Balance at December 31, 2016 8.2 Calendar 2017 Accretion expense 0.1 Settlements (0.3 ) Balance at December 31, 2017 $ 8.0 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 $132.8 million and $126.5 million in estimated costs of removal at December 31, 2017 and 2016 , 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, 2015 $ 121.8 Calendar 2016 Additions 11.7 Settlements (7.0 ) Balance at December 31, 2016 126.5 Calendar 2017 Additions 12.0 Settlements (5.7 ) Balance at December 31, 2017 $ 132.8 |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2017 | |
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, 2017 and 2016 . See Note 6 – Derivative Instruments and Hedging Activities for the fair values of our derivative instruments. December 31, 2017 December 31, 2016 $ in millions Cost Fair Value Cost Fair Value Assets Money market funds $ 0.3 $ 0.3 $ 0.4 $ 0.4 Equity securities 2.5 4.2 2.4 3.4 Debt securities 4.3 4.3 4.4 4.4 Hedge funds 0.1 0.2 — 0.1 Real estate — — 0.3 0.3 Tangible assets 0.1 0.1 0.1 0.1 Total assets $ 7.3 $ 9.1 $ 7.6 $ 8.7 Carrying Value Fair Value Carrying Value Fair Value Liabilities Long-term debt (a) $ 1,704.8 $ 1,819.3 $ 1,858.4 $ 1,907.7 (a) Amounts exclude immaterial capital lease obligations 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 (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 years ended December 31, 2017 and 2016 . 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 $1.6 million ( $1.0 million after tax) in unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at December 31, 2017 , and $1.0 million ( $0.6 million after tax) in unrealized gains and immaterial unrealized losses in AOCI at December 31, 2016 . During the year ended December 31, 2017 , $0.9 million ( $0.6 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, 2017 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, 2017 (a) Based on Other Unobservable inputs Assets Master trust assets Money market funds $ 0.3 $ 0.3 $ — $ — Equity securities 4.2 — 4.2 — Debt securities 4.3 — 4.3 — Hedge funds 0.2 — 0.2 — Real estate — — — — Tangible assets 0.1 — 0.1 — Total Master trust assets 9.1 0.3 8.8 — Derivative assets Forward power contracts 10.8 — 10.8 — Interest rate hedge 1.8 — 1.8 — Natural gas 0.2 0.2 — — Total Derivative assets 12.8 0.2 12.6 — Total assets $ 21.9 $ 0.5 $ 21.4 $ — Liabilities FTRs $ 0.3 $ — $ — $ 0.3 Natural gas 0.1 0.1 — — Forward power contracts 14.9 — 14.9 — Total derivative liabilities 15.3 0.1 14.9 0.3 Long-term debt (b) 1,819.3 — 1,801.5 17.8 Total liabilities $ 1,834.6 $ 0.1 $ 1,816.4 $ 18.1 (a) Includes credit valuation adjustment (b) Amounts exclude immaterial capital lease obligations 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 Other 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 hedges 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 Interest rate hedges $ 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 (b) 1,907.7 — 1,889.7 18.0 Fair value per table above $ 1,907.7 Total liabilities $ 1,936.9 $ — $ 1,916.4 $ 20.5 (a) Includes credit valuation adjustment (b) Amounts exclude immaterial capital lease obligations 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 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. Approximately 98.7% of the inputs to the fair value of our derivative instruments are from quoted market prices. Our long-term 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. As the Wright-Patterson Air Force Base 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 are not presented since our long-term debt is not recorded at fair value. 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 decreased due to changes in our estimates of costs to be incurred by a net amount of $2.6 million ( $1.7 million after tax) in 2017 and increased by a net amount of $72.9 million ( $47.4 million after tax) in 2016 largely driven by the increases to the AROs for the Stuart and Killen plants discussed below. 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. 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 (c) Level 1 Level 2 Level 3 Loss Long-lived assets (a) Year ended December 31, 2017 AES Ohio Generation peakers December 31, 2017 $ 346.9 $ — $ — $ 237.5 $ 109.4 Stuart March 31, 2017 $ 42.4 $ — $ — $ 3.3 $ 39.1 Killen March 31, 2017 $ 35.2 $ — $ — $ 7.9 27.3 $ 175.8 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 $ 859.0 Goodwill (b) Year ended December 31, 2015 DP&L reporting unit December 31, 2015 $ 317.0 $ — $ — $ — $ 317.0 (a) See Note 15 – Fixed-asset Impairments for further information (b) See Note 7 – Goodwill for further information (c) Carrying amount at date of valuation The following summarizes the significant unobservable inputs used in the Level 3 measurement on a non-recurring basis during the year ended December 31, 2017: $ in millions Measurement date Fair value Valuation technique Unobservable input Range (weighted average) Long-lived assets held and used: Year ended December 31, 2017 AES Ohio Generation peakers December 31, 2017 $ 237.5 Discounted cash flow Indicative offer price Stuart March 31, 2017 $ 3.3 Discounted cash flow Pre-tax operating margin 10.0% Weighted-average cost of capital 7.0% Killen March 31, 2017 $ 7.9 Discounted cash flow Pre-tax operating margin 22.0% Weighted-average cost of capital 7.0% 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, 2017 and 2016 . See also Note 6 – Derivative Instruments and Hedging Activities for the fair values of our derivative instruments. December 31, 2017 December 31, 2016 $ in millions Cost Fair Value Cost Fair Value Assets Money market funds $ 0.3 $ 0.3 $ 0.4 $ 0.4 Equity securities 2.5 4.2 2.4 3.4 Debt securities 4.3 4.3 4.4 4.4 Hedge funds 0.1 0.2 — 0.1 Real estate — — 0.3 0.3 Tangible assets 0.1 0.1 0.1 0.1 Total assets $ 7.3 $ 9.1 $ 7.6 $ 8.7 Carrying Value Fair Value Carrying Value Fair Value Liabilities Long-term debt (a) $ 646.6 $ 658.4 $ 735.7 $ 750.1 (a) Amounts exclude immaterial capital lease obligations in 2016 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 (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 years ended December 31, 2017 and 2016 . 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 $1.7 million ( $1.1 million after tax) in unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at December 31, 2017 and $1.1 million ( $0.7 million after tax) in unrealized gains and immaterial unrealized losses in AOCI at December 31, 2016 . During the year ended December 31, 2017 , $0.9 million ( $0.6 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, 2017 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, 2017 (a) Based on Other Unobservable inputs Assets Master trust assets Money market funds $ 0.3 $ 0.3 $ — $ — Equity securities 4.2 — 4.2 — Debt securities 4.3 — 4.3 — Hedge funds 0.2 — 0.2 — Real estate — — — — Tangible assets 0.1 — 0.1 — Total Master trust assets 9.1 0.3 8.8 — Derivative assets Interest rate hedges 1.8 — 1.8 — Total derivative assets 1.8 — 1.8 — Total assets $ 10.9 $ 0.3 $ 10.6 $ — Liabilities Long-term debt $ 658.4 $ — $ 640.6 $ 17.8 Total liabilities $ 658.4 $ — $ 640.6 $ 17.8 (a) Includes credit valuation adjustment (b) Amounts exclude immaterial capital lease obligations 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 Other 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 assets $ 8.7 $ 0.4 $ 8.3 $ — Liabilities Long-term debt (b) $ 750.1 $ — $ 732.1 $ 18.0 Total liabilities $ 750.1 $ — $ 732.1 $ 18.0 (a) Includes credit valuation adjustment (b) Amounts exclude immaterial capital lease obligations Our financial instruments are valued using the market approach in the following categories: • Level 1 inputs are used for financial contracts, such as 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 interest rate hedges. Other Level 2 assets include open-ended mutual funds in the Master Trust, which are valued using the end of day NAV per unit. • Level 3 inputs are used to value some debt which is not publicly traded. Our Level 3 inputs are immaterial to our derivative balances as a whole and as such no further disclosures are presented. Approximately 100% of the inputs to the fair value of our derivative instruments are from quoted market prices. Our long-term 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. As the Wright-Patterson Air Force Base 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 are not presented since our long-term debt is not recorded at fair value. 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 landfill, underground storage tanks, and river structures decreased by a net amount of $0.2 million ( $0.1 million after tax) and increased by a net amount of $3.2 million ( $2.1 million after tax) December 31, 2017 and 2016 , respectively. See Note 4 – Property, Plant and Equipment for more information about AROs. |
Derivative Instruments and Hedg
Derivative Instruments and Hedging Activities | 12 Months Ended |
Dec. 31, 2017 | |
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, 2017 , DPL's outstanding derivative instruments were as follows: Commodity Accounting Treatment (a) Unit Purchases Sales Net Purchases/ (Sales) FTRs Not designated MWh 2.1 — 2.1 Natural Gas Not designated Dths 3,322.5 (390.0 ) 2,932.5 Forward Power Contracts Designated MWh 678.5 (1,667.0 ) (988.5 ) Forward Power Contracts Not designated MWh 871.0 (765.6 ) 105.4 Interest Rate Swaps Designated USD $ 200,000.0 $ — $ 200,000.0 (a) Refers to whether the derivative instruments have been designated as a cash flow hedge. At December 31, 2016 , DPL's outstanding derivative instruments were as follows: Commodity Accounting Treatment (a) Unit Purchases Sales Net Purchases/ (Sales) 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 (a) Refers to whether the derivative instruments have been designated as a cash flow hedge. 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 considered to determine the hedge effectiveness of the cash flow hedges. We enter into forward power contracts and forward natural gas 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. We have 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 provide information on gains or losses recognized in AOCI for the cash flow hedges for the periods indicated: Years ended December 31, 2017 2016 2015 $ in millions (net of tax) Power Interest Rate Power Interest Rate Power Interest Rate Beginning accumulated derivative gain / (loss) in AOCI $ (4.3 ) $ 17.4 $ 9.2 $ 17.5 $ 0.2 $ 18.3 Net gains / (losses) associated with current period hedging transactions 8.8 0.8 15.7 0.4 18.2 — Net gains / (losses) reclassified to earnings: Interest Expense — (0.7 ) — (0.5 ) — (0.8 ) Revenues (9.8 ) — (35.6 ) — (12.0 ) — Purchased Power 2.5 — 6.4 — 2.8 — Ending accumulated derivative gain / (loss) in AOCI $ (2.8 ) $ 17.5 $ (4.3 ) $ 17.4 $ 9.2 $ 17.5 Portion expected to be reclassified to earnings in the next twelve months (a) $ (2.7 ) $ (0.7 ) Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) 3 32 (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. Net gains or losses associated with the ineffective portion of the hedging transactions were immaterial in the periods presented. 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. 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, 2017 , 2016 and 2015 : Year ended December 31, 2017 $ in millions FTRs Power Natural Gas Total Change in unrealized gain / (loss) $ (0.4 ) $ 1.9 $ 0.1 $ 1.6 Realized gain / (loss) 0.8 (0.7 ) 1.5 1.6 Total $ 0.4 $ 1.2 $ 1.6 $ 3.2 Recorded on Balance Sheet: Regulatory asset $ — $ — $ — $ — Recorded in Statement of Operations: gain / (loss) Revenue — (1.2 ) — (1.2 ) Purchased Power 0.4 2.4 1.6 4.4 Total $ 0.4 $ 1.2 $ 1.6 $ 3.2 Year ended December 31, 2016 $ in millions FTRs Power Natural Gas Total 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 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) Fuel — — 27.4 — 27.4 Purchased Power — 0.1 (43.6 ) — (43.5 ) Total $ 0.1 $ 0.1 $ (16.2 ) $ — $ (16.0 ) DPL has elected not to offset derivative assets and liabilities and not to offset net derivative positions against the right to reclaim cash collateral pledged (an asset) or the obligation to return cash collateral received (a liability) under derivative agreements. The following tables summarize the derivative positions presented in the balance sheet where a right of offset exists under these arrangements and related cash collateral received or pledged; as well as the fair value, balance sheet classification and hedging designation of DPL’s derivative instruments. Fair Values of Derivative Instruments December 31, 2017 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 $ 4.9 $ (4.9 ) $ — $ — Forward power contracts Not designated 5.3 (3.7 ) — 1.6 Natural gas Not designated 0.2 (0.1 ) — 0.1 Long-term derivative positions (presented in Other deferred assets) Interest Rate Swaps Designated 1.8 — — 1.8 Forward power contracts Designated — — — — Forward power contracts Not designated 0.6 — — 0.6 Total assets $ 12.8 $ (8.7 ) $ — $ 4.1 Liabilities Short-term derivative positions (presented in Other current liabilities) Forward power contracts Designated $ 9.0 $ (4.9 ) $ (1.4 ) $ 2.7 Forward power contracts Not designated 5.9 (3.7 ) — 2.2 Natural gas Not designated 0.1 (0.1 ) — — FTRs Not designated 0.3 — — 0.3 Total liabilities $ 15.3 $ (8.7 ) $ (1.4 ) $ 5.2 (a) Includes credit valuation adjustment. 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 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. Credit risk-related contingent features Certain of our OTC commodity derivative contracts are under master netting agreements that contain provisions that require us to post collateral if our credit ratings drop below certain thresholds. We have crossed this threshold and our counterparties could request that we post collateral for our net liability position with them. As of the date of the filing of this report, we have not had to post collateral with any of these counterparties. The aggregate fair value of DPL’s derivative instruments that were in a MTM loss position at December 31, 2017 is $15.3 million . This amount is offset by $8.7 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 $1.4 million . Since our debt is below investment grade, we could have to post collateral for the remaining $4.9 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. DP&L's interest rate swaps are designated as a cash flow hedge. At December 31, 2017 and 2016 , the principal balance of the interest rate hedges was $200.0 million . 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 considered to determine the hedge effectiveness of the cash flow hedges. We have 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 provide information on gains or losses recognized in AOCI for the cash flow hedges for the periods indicated: Years ended December 31, 2017 2016 2015 $ in millions (net of tax) Power Interest Rate Power Interest Rate Power Interest Rate Beginning accumulated derivative gain / (loss) in AOCI $ (4.3 ) $ 1.6 $ 9.2 $ 2.0 $ 0.2 $ 2.6 Net gains / (losses) associated with current period hedging transactions 10.7 1.7 15.7 0.4 18.2 — Net gains / (losses) reclassified to earnings: Interest expense — (0.7 ) — (0.8 ) — (0.6 ) Loss from discontinued operations (5.5 ) — (29.2 ) — (9.2 ) — Transfer of generation assets to subsidiary of parent $ (2.1 ) $ — $ — $ — $ — $ — Ending accumulated derivative gain / (loss) in AOCI $ (1.2 ) $ 2.6 $ (4.3 ) $ 1.6 $ 9.2 $ 2.0 Portion expected to be reclassified to earnings in the next twelve months $ (0.7 ) Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) 32 Net gains or losses associated with the ineffective portion of the hedging transactions were immaterial in the periods presented. DP&L has elected not to offset derivative assets and liabilities and not to offset net derivative positions against the right to reclaim cash collateral pledged (an asset) or the obligation to return cash collateral received (a liability) under derivative agreements. The fair value derivative position of DP&L's interest rate swaps are as follows: December 31, Hedging Designation Balance sheet classification 2017 2016 Interest Rate Hedges in an Asset Position Cash Flow Hedge Other Deferred Assets Gross Fair Value as presented in the Balance Sheets $ 1.8 $ 1.2 Interest Rate Hedges in a Liability Position Cash Flow Hedge Other Current Liabilities Gross Fair Value as presented in the Balance Sheets $ — $ 0.7 |
Goodwill and Other Intangible A
Goodwill and Other Intangible Assets | 12 Months Ended |
Dec. 31, 2017 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Goodwill and Intangible Assets | Goodwill 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, 2017 | |
Debt Instrument [Line Items] | |
Debt | Debt Long-term debt $ in millions Interest Rate Maturity December 31, 2017 December 31, 2016 Term loan - rates from: 4.01% - 4.60% (a) and 4.00% - 4.01% (b) 2022 $ 440.6 $ 445.0 Tax-exempt First Mortgage Bonds 4.8% 2036 — 100.0 Tax-exempt First Mortgage Bonds - rates from: 1.52% - 1.92% (a) and 1.29% - 1.42% (b) 2020 200.0 200.0 U.S. Government note 4.2% 2061 17.8 18.0 Capital leases 0.2 0.4 Unamortized deferred financing costs (9.8 ) (10.7 ) Unamortized debt discounts and premiums, net (2.0 ) (5.5 ) Total long-term debt at subsidiary 646.8 747.2 Bank term loan - rates from: 3.02% - 4.10% (a) and 2.67% - 3.02% (b) 2020 70.0 125.0 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 (6.8 ) (8.8 ) Unamortized debt discounts and premiums, net (0.5 ) (0.6 ) Total long-term debt 1,705.1 1,858.4 Less: current portion (4.7 ) (29.7 ) Long-term debt, net of current portion $ 1,700.4 $ 1,828.7 (a) Range of interest rates for the year ended December 31, 2017 . (b) Range of interest rates for the year ended December 31, 2016 . (c) Note payable to related party. See Note 13 – Related Party Transactions for additional information. At December 31, 2017 , maturities of long-term debt are summarized as follows: Due during the years ending December 31, $ in millions 2018 $ 4.7 2019 224.5 2020 254.6 2021 784.6 2022 422.9 Thereafter 32.7 1,724.0 Unamortized discounts and premiums, net (2.5 ) Total long-term debt $ 1,721.5 Premiums or discounts recognized at the Merger date are amortized over the life of the debt using the effective interest method. Significant transactions On January 3, 2018, DP&L and its lenders amended DP&L's Term Loan B credit agreement. The amendment (a) modified the definition of "applicable rate", from 2.25% per annum to 1.00% per annum - in the case of the Base Rate, and from 3.25% per annum to 2.00% per annum - in the case of the Eurodollar Rate, and (b) included a "call protection" provision which stated that in the event the loan was repriced or any portion of the loans were prepaid, repaid, refinanced, substituted, or replaced on or prior July 3, 2018, such prepayment, acceleration, repayment, refinancing, substitution or replacement would be made at 101% of the principal amount so prepaid, repaid, refinanced, substituted or replaced. After July 3, 2018 any such transaction would occur at 100% of the principal amount of the then outstanding loans. On December 15, 2017, shortly after DPL and AES Ohio Generation entered into an Asset Purchase Agreement agreeing to sell Peaker assets to Kimura Power, DPL and its lenders amended DPL's revolving credit loan and term loan credit agreement. This agreement was amended to, among other things, (a) explicitly carve out the sale of DPL's Peaker assets and coal generation facilities from its "limitation on asset disposition" covenant, (b) modify the definition of Consolidated EBITDA (which is used for measuring the Consolidated Debt to EBITDA ratio and the Interest Coverage Ratio in the agreement), to also exclude, out-of-pocket third party costs and expenses incurred directly in connection with the implementation, negotiation, documentation and closing of the Generation Separation and up to $25.0 million of non-recurring cash expenses related to the closure, or sale, of generation stations, (c) modify the definition of "maturity date" used in the agreement to mean July 31, 2020; provided, however, if DPL fails to retire, redeem, or refinance at least $100.0 million in aggregate of principal amount of its senior unsecured bonds due October 1, 2019, then the maturity date shall be July, 1 2019, and (d) modify the maximum Consolidated Debt to EBITDA ratio permitted not to exceed 7.25 to 1.00 September 20, 2015 through December 31, 2018, 7.00 to 1.00 January 1, 2019 through June 30, 2019, 6.75 to 1.00 July 1, 2019 through December 31, 2019, and 6.50 to 1.00 January 1, 2020 and beyond. As part of this agreement DPL has also agreed to repay the remaining balance on its secured term loan within 10 days after receiving proceeds from the sale of the Peaker assets. This agreement was effective December 15, 2017, however certain provisions, including the modification of the Consolidated Debt to EBITDA covenant and the carving out of the sale of Peaker assets from its "limitation on asset disposition" covenant, are conditioned on the repayment in full of the term loan. On December 8, 2017, DPL made a $30.0 million prepayment on its term loan. As of December 31, 2017, the outstanding balance was $70.0 million . On May 26, 2017, DP&L commenced a tender offer to purchase any and all of the outstanding 4.8% tax-exempt First Mortgage Bonds at par value (plus accrued and unpaid interest). By June 23, 2017, or the expiration date of the tender, $8.1 million of the outstanding bonds were tendered. On June 26, 2017, DP&L accepted all of the tendered bonds, redeemed and retired them. On July 7, 2017, DP&L notified the Ohio Air Quality Development Authority and the Trustee of the same First Mortgage Bonds that DP&L was going to call at par value (plus accrued and unpaid interest) $21.9 million of these bonds. This call was completed on August 7, 2017. On September 28, 2017, DP&L issued an irrevocable call notice to purchase all of the remaining outstanding 4.8% tax-exempt First Mortgage Bonds at par value (plus accrued and unpaid interest). As of September 30, 2017, all of the bonds were either redeemed or defeased. This was done to facilitate Generation Separation and the release of the DP&L generation assets from the lien of DP&L's First and Refunding Mortgage. The redemption of the $70.0 million principal amount of bonds was completed on October 30, 2017. 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 $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, 2017 , DPL’s leverage ratio was at 1.50 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, 2017 , 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). DPL is also restricted from making dividend and tax sharing payments from DPL to AES per its 2017 ESP. This order restricts dividend payments from DPL to AES during the term of the 2017 ESP and restricts tax sharing payments from DPL to AES during the term of the DMR. See Note 9 – Income Taxes for more information. DP&L’s revolving credit facility and Bond Purchase and Covenants Agreement (financing document entered into in connection with the issuance of the $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, which occurred October 1, 2017, 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 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 was able to ensure compliance with the Total Debt to Total Capitalization ratio through October 1, 2017, the date Generation Separation occurred. After Generation Separation, and per the terms of the original agreement (before any amendment), the required Total Debt to Total Capitalization ratio increased from 0.65 to 1.00 to 0.75 to 1.00. On September 30, 2017, DP&L's adjusted (excluding impairments) Total Debt to Total Capitalization was 0.61 to 1.00 and as of December 31, 2017 it was 0.67 to 1.00 . After Generation Separation occurred, the calculation of this covenant is on an unadjusted basis. The amendment also changed, for each agreement, the dates after Generation Separation during which compliance with the Total Capitalization ratio detailed above will 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 (or from October 1, 2017 through September 30, 2018) . Generation Separation occurred on October 1, 2017. As of December 31, 2017 , DP&L and DPL were in compliance with all debt covenants, including the financial covenants described above. Substantially all property, plant & equipment of DP&L is subject to the lien of the mortgage securing DP&L’s First and Refunding Mortgage. All generation assets were released from the lien of DP&L's first and refunding mortgage in connection with the completion of Generation Separation on October 1, 2017. |
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, 2017 December 31, 2016 Term loan - rates from: 4.01% - 4.60% (a) and 4.00% - 4.01% (b) 2022 $ 440.6 $ 445.0 Tax-exempt First Mortgage Bonds 4.8% 2036 — 100.0 Tax-exempt First Mortgage Bonds - rates from: 1.52% - 1.92% (a) and 1.29% - 1.42% (b) 2020 200.0 200.0 U.S. Government note 4.2% 2061 17.8 18.0 Capital leases — 0.4 Debt classified as held-for-sale — (13.4 ) Unamortized deferred financing costs (9.8 ) (11.7 ) Unamortized debt discount (2.0 ) (2.2 ) Total long-term debt 646.6 736.1 Less: current portion (4.6 ) (4.6 ) Long-term debt, net of current portion $ 642.0 $ 731.5 (a) Range of interest rates for the year ended December 31, 2017 . (b) Range of interest rates for the year ended December 31, 2016 . At December 31, 2017 , maturities of long-term debt are summarized as follows: Due during the years ending December 31, $ in millions 2018 $ 4.6 2019 4.6 2020 204.6 2021 4.6 2022 422.9 Thereafter 17.1 658.4 Unamortized discounts and premiums, net (2.0 ) Total long-term debt $ 656.4 Significant transactions On January 3, 2018, DP&L and its lenders amended DP&L's Term Loan B credit agreement. The amendment (a) modified the definition of "applicable rate", from 2.25% per annum to 1.00% per annum - in the case of the Base Rate, and from 3.25% per annum to 2.00% per annum - in the case of the Eurodollar Rate, and (b) included a "call protection" provision which stated that in the event the loan was repriced or any portion of the loans were prepaid, repaid, refinanced, substituted, or replaced on or prior July 3, 2018, such prepayment, acceleration, repayment, refinancing, substitution or replacement would be made at 101% of the principal amount so prepaid, repaid, refinanced, substituted or replaced. After July 3, 2018 any such transaction would occur at 100% of the principal amount of the then outstanding loans. On May 26, 2017, DP&L commenced a tender offer to purchase any and all of the outstanding 4.8% tax-exempt First Mortgage Bonds at par value (plus accrued and unpaid interest). By June 23, 2017, or the expiration date of the tender, $8.1 million of the outstanding bonds were tendered. On June 26, 2017, DP&L accepted all of the tendered bonds, redeemed and retired them. On July 7, 2017, DP&L notified the Ohio Air Quality Development Authority and the Trustee of the same First Mortgage Bonds that DP&L was going to call at par value (plus accrued and unpaid interest) $21.9 million of these bonds. This call was completed on August 7, 2017. On September 28, 2017, DP&L issued an irrevocable call notice to purchase all of the remaining outstanding 4.8% tax-exempt First Mortgage Bonds at par value (plus accrued and unpaid interest). As of September 30, 2017, all of the bonds were either redeemed or defeased. This was done to facilitate Generation Separation and the release of the DP&L generation assets from the lien of DP&L's First and Refunding Mortgage. The redemption of the $70.0 million principal amount of bonds was completed on October 30, 2017. 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 was able to ensure compliance with the Total Debt to Total Capitalization ratio through October 1, 2017, the date Generation Separation occurred. After Generation Separation, and per the terms of the original agreement (before any amendment), the required Total Debt to Total Capitalization ratio increased from 0.65 to 1.00 to 0.75 to 1.00. On September 30, 2017, DP&L's adjusted (excluding impairments) Total Debt to Total Capitalization was 0.61 to 1.00 and as of December 31, 2017 it was 0.67 to 1.00 . After Generation Separation occurred, the calculation of this covenant is on an unadjusted basis. The amendment also changed, for each agreement, the dates after Generation Separation during which compliance with the Total Capitalization ratio detailed above will 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 (or from October 1, 2017 through September 30, 2018) . Generation Separation occurred on October 1, 2017. 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. 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 $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. DP&L’s revolving credit facility and Bond Purchase and Covenants Agreement (financing document entered into in connection with the issuance of the $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, which occurred October 1, 2017, 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 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 was able to ensure compliance with the Total Debt to Total Capitalization ratio through October 1, 2017, the date Generation Separation occurred. After Generation Separation, and per the terms of the original agreement (before any amendment), the required Total Debt to Total Capitalization ratio increased from 0.65 to 1.00 to 0.75 to 1.00. On September 30, 2017, DP&L's adjusted (excluding impairments) Total Debt to Total Capitalization was 0.61 to 1.00 and as of December 31, 2017 it was 0.67 to 1.00 . After Generation Separation occurred, the calculation of this covenant is on an unadjusted basis. The amendment also changed, for each agreement, the dates after Generation Separation during which compliance with the Total Capitalization ratio detailed above will 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 (or from October 1, 2017 through September 30, 2018) . Generation Separation occurred on October 1, 2017. As of December 31, 2017 , 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 . Substantially all property, plant & equipment of DP&L is subject to the lien of the mortgage securing DP&L’s First and Refunding Mortgage. All generation assets were released from the lien of DP&L's first and refunding mortgage in connection with the completion of Generation Separation on October 1, 2017. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2017 | |
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 2017 2016 2015 Computation of tax expense / (benefit) Federal income tax benefit (a) $ (42.0 ) $ (277.6 ) $ (81.0 ) Increases (decreases) in tax resulting from: State income taxes, net of federal effect (0.5 ) (1.0 ) (0.1 ) Depreciation of AFUDC - Equity 0.8 2.7 (3.5 ) Investment tax credit amortized (0.3 ) (0.4 ) (0.5 ) Section 199 - domestic production deduction — (4.5 ) (4.1 ) Non-deductible goodwill impairment — — 111.0 Accrual (settlement) for open tax years (0.4 ) 2.2 — Other, net (b) 17.1 (0.2 ) (1.8 ) Tax expense / (benefit) $ (25.3 ) $ (278.8 ) $ 20.0 Components of tax expense / (benefit) Federal - current $ (2.9 ) $ 14.7 $ 30.1 State and Local - current — 0.6 0.8 Total current (2.9 ) 15.3 30.9 Federal - deferred (22.0 ) (290.2 ) (9.9 ) State and local - deferred (0.4 ) (3.9 ) (1.0 ) Total deferred (22.4 ) (294.1 ) (10.9 ) Tax expense / (benefit) $ (25.3 ) $ (278.8 ) $ 20.0 (a) The statutory tax rate of 35% was applied to pre-tax earnings. (b) Includes expense / (benefit) of $3.5 million , $(0.3) million and $0.2 million in the years ended December 31, 2017 , 2016 , and 2015 , respectively, of income tax related to adjustments from prior years. The 2017 tax year also includes a one-time remeasurement of deferred tax expense related to the recent enactment of the TCJA of $13.7 million . 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, 2017 , 2016 and 2015 : Years ended December 31, 2017 2016 2015 Statutory Federal tax rate 35.0 % 35.0 % 35.0 % State taxes, net of Federal tax benefit 0.4 % 0.1 % 0.1 % AFUDC - Equity (0.7 )% (0.3 )% 1.5 % Amortization of investment tax credits 0.3 % — % 0.2 % Section 199 - domestic production deduction — % 0.6 % 1.8 % Non-deductible goodwill impairment — % — % (48.0 )% Other, net (a) (13.9 )% (0.3 )% 0.8 % Effective tax rate 21.1 % 35.1 % (8.6 )% (a) In 2017, this is primarily a result of the application of the TCJA. 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 2017 2016 Net non-current assets / (liabilities) Depreciation / property basis $ (103.6 ) $ (234.8 ) Income taxes recoverable / (payable) 11.0 (11.9 ) Regulatory assets (23.1 ) (7.8 ) Investment tax credit 0.5 0.5 Compensation and employee benefits 11.3 5.5 Intangibles (0.4 ) (1.5 ) Long-term debt (0.2 ) (0.7 ) Other (a) (6.7 ) (1.7 ) Net non-current liabilities $ (111.2 ) $ (252.4 ) (a) The Other caption includes deferred tax assets of $36.3 million in 2017 and $38.3 million in 2016 related to state and local tax net operating loss carryforwards, net of related valuation allowances of $36.3 million in 2017 and $38.3 million in 2016 . These net operating loss carryforwards expire from 2018 to 2037. U. S Tax Reform On December 22, 2017, the U.S. enacted the TCJA. The TCJA significantly changes U.S. corporate income tax law. We recognized the income tax effects of the TCJA in accordance with Staff Accounting Bulletin No. 118 (“SAB 118”) which provides SEC guidance on the application of FASC 740, Income Taxes, in the reporting period in which the TCJA was signed into law. Accordingly, our financial statements reflect the income tax effects of U.S. tax reform for which the accounting is complete and provisional amounts for those impacts for which the accounting under FASC 740 is incomplete, but a reasonable estimate could be determined. We have calculated our best estimate of the impact of the TCJA in our income tax provision for the year ended December 31, 2017 in accordance with our understanding of the TCJA and guidance available as of the date of this filing , and as a result recognized $13.7 million of discrete tax expense in the fourth quarter of 2017 related to non-operating and non-regulated property. This amount results from the remeasurement of certain deferred tax assets and liabilities from 35% to 21% . The most material deferred taxes to be remeasured related to property, plant and equipment. The remeasurement of deferred tax assets and liabilities related to regulated utility property of $135.2 million was recorded as a regulatory liability, which was a non-cash adjustment. Additional time is required to finalize remeasurement effects in accordance with GAAP. Per the terms of the order issued by the PUCO on DP&L 's 2017 ESP, DPL will not make any tax-sharing payments to AES and AES will forgo collection of the payments during the term of the DMR. The agreed upon term of the DMR is three years. With commission approval, the DMR can be extended two additional years allowing for the term to potentially be five years. Both the current and non-current existing tax sharing liabilities with AES were converted into additional equity investment in DPL , per the requirements of the order. Throughout the term, further accrued tax sharing liabilities will also be converted to additional equity. All parties agreed that the initial conversion and any future conversions will not be reversed. In 2017 we converted $97.1 million to equity in accordance with this requirement. 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 2017 2016 2015 Tax expense / (benefit) $ 0.2 $ (9.6 ) $ 6.3 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, 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 Calendar 2017 Tax positions taken during prior period — Lapse of Statute of Limitations (0.2 ) Balance at December 31, 2017 $ 3.5 Of the December 31, 2017 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 the 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. |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Income Taxes [Line Items] | |
Income Taxes | Income Taxes DP&L’s components of income tax expense on continuing operations were as follows: Years ended December 31, $ in millions 2017 2016 2015 Computation of tax expense Federal income tax expense (a) $ 31.0 $ 50.1 $ 65.8 Increases (decreases) in tax resulting from: State income taxes, net of federal effect 0.4 0.4 0.4 Depreciation of AFUDC - Equity 1.2 3.0 (3.1 ) Investment tax credit amortized (0.3 ) (0.4 ) (0.4 ) Accrual (settlement) for open tax years (0.5 ) 3.4 — Other, net (b) (0.7 ) (10.5 ) (3.7 ) Total tax expense $ 31.1 $ 46.0 $ 59.0 Components of tax expense Federal - current $ 13.5 $ 37.7 $ 68.3 State and Local - current 0.2 0.5 0.9 Total current 13.7 38.2 69.2 Federal - deferred 17.0 7.7 (9.9 ) State and local - deferred 0.4 0.1 (0.3 ) Total deferred 17.4 7.8 (10.2 ) Total tax expense $ 31.1 $ 46.0 $ 59.0 (a) The statutory tax rate of 35% was applied to pre-tax earnings. (b) Includes expense / (benefit) of $0.0 million , $(0.4) million and $0.1 million in the years ended December 31, 2017 , 2016 and 2015 , 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, 2017 , 2016 and 2015 : Years ended December 31, 2017 2016 2015 Statutory Federal tax rate 35.0 % 35.0 % 35.0 % State taxes, net of Federal tax benefit 0.4 % 0.3 % 0.2 % AFUDC - Equity 1.4 % 2.1 % (1.7 )% Amortization of investment tax credits (0.4 )% (0.3 )% (0.2 )% Other - net (1.3 )% (5.1 )% (2.1 )% Effective tax rate 35.1 % 32.0 % 31.2 % 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 2017 2016 Net non-current assets / (liabilities) Depreciation / property basis $ (126.5 ) $ (238.0 ) Income taxes recoverable / (payable) 11.0 (12.2 ) Regulatory assets (23.9 ) (9.1 ) Investment tax credit 0.4 0.4 Compensation and employee benefits 17.6 (0.3 ) Other (9.6 ) (7.7 ) Net non-current liabilities $ (131.0 ) $ (266.9 ) U. S Tax Reform On December 22, 2017, the U.S. enacted the TCJA. The TCJA significantly changes U.S. corporate income tax law. We recognized the income tax effects of the TCJA in accordance with Staff Accounting Bulletin No. 118 (“SAB 118”) which provides SEC guidance on the application of FASC 740, Income Taxes, in the reporting period in which the TCJA was signed into law. Accordingly, our financial statements reflect the income tax effects of U.S. tax reform for which the accounting is complete and provisional amounts for those impacts for which the accounting under FASC 740 is incomplete, but a reasonable estimate could be determined. We have calculated our best estimate of the impact of the TCJA in our income tax provision for the year ended December 31, 2017 in accordance with our understanding of the TCJA and guidance available as of the date of this filing . Certain deferred tax assets and liabilities were remeasured as the rates changed from 35% to 21% . The most material deferred taxes to be remeasured related to property, plant and equipment. The remeasurement of deferred tax assets and liabilities related to regulated utility property of $135.2 million was recorded as a regulatory liability, which was a non-cash adjustment. Additional time is required to finalize remeasurement effects in accordance with GAAP. 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 2017 2016 2015 Tax expense / (benefit) $ 4.0 $ (7.0 ) $ 7.5 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, 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 Calendar 2017 Tax positions taken during prior period — Lapse of Statute of Limitations (0.1 ) Balance at December 31, 2017 $ 4.8 Of the December 31, 2017 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 tax 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, 2017 | |
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 $2,300 for 2017 and they are fully vested in their employer contributions after 3 years of service. All participants are fully vested in their own contributions. We contributed $3.1 million, $5.1 million and $4.9 million in the years ended December 31, 2017, 2016 and 2015, respectively. DP&L matching contributions are paid quarterly, in arrears. Therefore, the contributions by year include the fourth quarter matching contribution that is paid in the following year. DP&L also contributes an annual bonus to the accounts of its union participants. This payment is typically made in January of the following year. For 2017, the annual bonus amount is yet to be determined and paid; pending the results of negotiations with the bargaining unit. Defined benefit pl ans 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 formula 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 formula. 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 liabilities 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 $12.7 million and $15.8 million at December 31, 2017 and 2016 , 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 Consolidated Balance Sheets at December 31, 2017 and 2016 . 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 $1.1 million and $1.3 million of costs billed to the service company for the years ended December 31, 2017 and 2016 . $ in millions Years ended December 31, Change in benefit obligation 2017 2016 Benefit obligation at January 1 $ 419.6 $ 410.8 Service cost 5.7 5.7 Interest cost 14.2 14.7 Plan curtailment 3.0 2.5 Actuarial loss 28.1 9.0 Benefits paid (33.7 ) (23.1 ) Benefit obligation at December 31 436.9 419.6 Change in plan assets Fair value of plan assets at January 1 341.0 345.4 Actual return on plan assets 44.8 13.3 Employer contributions 5.4 5.4 Benefits paid (33.7 ) (23.1 ) Fair value of plan assets at December 31 357.5 341.0 Unfunded status of plan $ (79.4 ) $ (78.6 ) December 31, Amounts recognized in the Balance sheets 2017 2016 Current liabilities $ (0.4 ) $ (0.4 ) Non-current liabilities (79.0 ) (78.2 ) Net liability at end of year $ (79.4 ) $ (78.6 ) Amounts recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax Components: Prior service cost $ 4.9 $ 8.8 Net actuarial loss 111.4 108.9 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 116.3 $ 117.7 Recorded as: Regulatory asset $ 92.1 $ 97.1 Accumulated other comprehensive income 24.2 20.6 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 116.3 $ 117.7 The accumulated benefit obligation for our defined benefit pension plans was $428.3 million and $409.2 million at December 31, 2017 and 2016 , respectively. The net periodic benefit cost of the pension plans was: Years ended December 31, $ in millions 2017 2016 2015 Service cost $ 5.7 $ 5.7 $ 7.1 Interest cost 14.2 14.7 17.3 Expected return on assets (22.8 ) (22.8 ) (22.6 ) Plan curtailment 4.1 3.8 — Amortization of unrecognized: Actuarial loss 5.3 4.3 5.8 Prior service cost 1.1 1.8 2.0 Net periodic benefit cost $ 7.6 $ 7.5 $ 9.6 Rates relevant to each year's expense calculations Discount rate 4.28 % 4.49 % 4.02 % Expected return on plan assets 6.50 % 6.50 % 6.50 % 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 2017 2016 2015 Net actuarial loss / (gain) $ 9.1 $ 20.9 $ (3.0 ) Prior service cost — — — Plan curtailment (4.1 ) (3.8 ) — Reversal of amortization item: Net actuarial loss (5.3 ) (4.3 ) (5.8 ) Prior service cost (1.1 ) (1.8 ) (2.0 ) Total recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities $ (1.4 ) $ 11.0 $ (10.8 ) Total recognized in net periodic benefit cost and Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities $ 6.2 $ 18.5 $ (1.2 ) Estimated amounts that will be amortized from AOCI, Regulatory assets and Regulatory liabilities into net periodic benefit costs during 2018 are: $ in millions Pension Actuarial loss $ 6.4 Prior service cost $ 0.9 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, 2017 , we are decreasing our long-term rate of return assumption to 6.25% for pension plan assets. The rate of return represents our long-term assumptions based on our long-term portfolio mix. Also, at December 31, 2017 , we have decreased our assumed discount rate to 3.66% from 4.28% 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 2018 pension expense of approximately $3.4 million . A one percent decrease in the rate of return assumption for pension would result in an increase in 2018 pension expense of approximately $3.4 million . A 25 -basis point increase in the discount rate for pension would result in a decrease of approximately $0.6 million to 2018 pension expense. A 25 -basis point decrease in the discount rate for pension would result in an increase of approximately $0.6 million to 2018 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, 2017 . 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, 2017 , 2016 and 2015 were: Benefit Obligation Assumptions Pension 2017 2016 2015 Discount rate for obligations 3.66% 4.28% 4.49% 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 consider the plan’s long-term objectives. The long-term target allocations for plan assets are 24% – 52% for equity securities and 47% – 65% 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 in 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 2017 : Long-Term Percentage of plan assets as of December 31, Asset category 2017 2016 Equity Securities 38% 35% 37% Debt Securities 56% 55% 53% Real Estate 6% 10% 10% The fair values of our pension plan assets at December 31, 2017 by asset category are as follows: Fair Value Measurements for Pension Plan Assets at December 31, 2017 $ in millions Market Value at December 31, 2017 Quoted prices Significant Significant Asset category (Level 1) (Level 2) (Level 3) Mutual funds: U.S. equities (a) $ 78.2 $ 78.2 $ — $ — International equities (a) 46.3 46.3 — — Fixed income (b) 163.3 163.3 — — Fixed income securities: U.S. Treasury securities 33.5 33.5 — — Other investments: Core property collective fund (c) 36.2 — 36.2 — Total pension plan assets $ 357.5 $ 321.3 $ 36.2 $ — (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, 2016 by asset category are as follows: Fair Value Measurements for Pension Plan Assets at December 31, 2016 $ in millions Market Value at December 31, 2016 Quoted prices Significant Significant Asset category (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: (c) Core property collective fund 33.1 — 33.1 — Common collective fund — — — — 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. 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 to the pension plan in each of the years ended December 31, 2017, 2016 and 2015. We expect to make contributions of $0.4 million to our SERP in 2018 to cover benefit payments. We made contributions of $7.5 million to our pension plan during January 2018 . Funding for the qualified Defined Benefit Pension Plan is based upon actuarially determined contributions that consider 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 99% . 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 $7.5 million in 2018 , which includes $2.2 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 2018 $ 28.4 2019 $ 28.2 2020 $ 27.9 2021 $ 27.6 2022 $ 27.3 2023 - 2027 $ 131.3 |
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 $2,300 for 2017 and they are fully vested in their employer contributions after 3 years of service. All participants are fully vested in their own contributions. We contributed $3.1 million, $5.1 million and $4.9 million in the years ended December 31, 2017, 2016 and 2015, respectively. DP&L matching contributions are paid quarterly, in arrears. Therefore, the contributions by year include the fourth quarter matching contribution that is paid in the following year. DP&L also contributes an annual bonus to the accounts of its union participants. This payment is typically made in January of the following year. For 2017, the annual bonus amount is yet to be determined and paid; pending the results of negotiations with the bargaining unit. Defined benefit pl ans 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 formula 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. In addition, employees that transferred from DP&L to AES Ohio Generation due to Generation Separation 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 formula. 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 liabilities 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 $12.7 million and $15.8 million at December 31, 2017 and 2016 , 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, 2017 and 2016 . 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 $1.1 million and $1.3 million of costs billed to the service company for the years ended December 31, 2017 and 2016 or $0.7 million of costs billed to AES Ohio Generation for the year ended December 31, 2017. $ in millions Years ended December 31, Change in benefit obligation 2017 2016 Benefit obligation at January 1 $ 419.6 $ 410.8 Service cost 5.7 5.7 Interest cost 14.2 14.7 Plan curtailment 3.0 2.5 Actuarial loss 28.1 9.0 Benefits paid (33.7 ) (23.1 ) Benefit obligation at December 31 436.9 419.6 Change in plan assets Fair value of plan assets at January 1 341.0 345.4 Actual return on plan assets 44.8 13.3 Employer contributions 5.4 5.4 Benefits paid (33.7 ) (23.1 ) Fair value of plan assets at December 31 357.5 341.0 Unfunded status of plan $ (79.4 ) $ (78.6 ) December 31, Amounts recognized in the Balance sheets 2017 2016 Current liabilities $ (0.4 ) $ (0.4 ) Non-current liabilities (79.0 ) (78.2 ) Net liability at end of year $ (79.4 ) $ (78.6 ) Amounts recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax Components: Prior service cost $ 6.7 $ 8.8 Net actuarial loss 148.3 108.9 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 155.0 $ 117.7 Recorded as: Regulatory asset $ 92.2 $ 97.1 Accumulated other comprehensive income 62.8 20.6 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 155.0 $ 117.7 The accumulated benefit obligation for our defined benefit pension plans was $428.3 million and $409.2 million at December 31, 2017 and 2016 , respectively. The net periodic benefit cost of the pension plans was: Years ended December 31, $ in millions 2017 2016 2015 Service cost $ 5.7 $ 5.7 $ 7.1 Interest cost 14.2 14.7 17.3 Expected return on assets (22.8 ) (22.8 ) (22.6 ) Plan curtailment 5.6 5.7 — Amortization of unrecognized: Actuarial loss 8.7 7.2 9.8 Prior service cost 1.5 3.0 3.3 Net periodic benefit cost $ 12.9 $ 13.5 $ 14.9 Rates relevant to each year's expense calculations Discount rate 4.28 % 4.49 % 4.02 % Expected return on plan assets 6.50 % 6.50 % 6.50 % 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 2017 2016 2015 Net actuarial loss / (gain) $ 9.1 $ 20.9 $ (3.0 ) Prior service cost — — — Plan curtailment (5.6 ) (5.7 ) — Reversal of amortization item: Net actuarial loss (8.7 ) (7.2 ) (9.8 ) Prior service cost (1.5 ) (3.0 ) (3.3 ) Total recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities $ (6.7 ) $ 5.0 $ (16.1 ) Total recognized in net periodic benefit cost and Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities $ 6.2 $ 18.5 $ (1.2 ) Estimated amounts that will be amortized from AOCI, Regulatory assets and Regulatory liabilities into net periodic benefit costs during 2018 are: $ in millions Pension Actuarial loss $ 9.4 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, 2017 , we are decreasing our long-term rate of return assumption to 6.25% for pension plan assets. The rate of return represents our long-term assumptions based on our long-term portfolio mix. Also, at December 31, 2017 , we have decreased our assumed discount rate to 3.66% from 4.28% 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 2018 pension expense of approximately $3.4 million . A one percent decrease in the rate of return assumption for pension would result in an increase in 2018 pension expense of approximately $3.4 million . A 25 -basis point increase in the discount rate for pension would result in a decrease of approximately $0.6 million to 2018 pension expense. A 25 -basis point decrease in the discount rate for pension would result in an increase of approximately $0.6 million to 2018 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, 2017 . 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, 2017 , 2016 and 2015 were: Benefit Obligation Assumptions Pension 2017 2016 2015 Discount rate for obligations 3.66% 4.28% 4.49% 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 consider the plan’s long-term objectives. The long-term target allocations for plan assets are 24% – 52% for equity securities and 47% – 65% 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 in 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 2017 : Long-Term Percentage of plan assets as of December 31, Asset category 2017 2016 Equity Securities 38% 35% 37% Debt Securities 56% 55% 53% Real Estate 6% 10% 10% The fair values of our pension plan assets at December 31, 2017 by asset category are as follows: Fair Value Measurements for Pension Plan Assets at December 31, 2017 $ in millions Market Value at December 31, 2017 Quoted prices Significant Significant Asset category (Level 1) (Level 2) (Level 3) Mutual funds: U.S. equities (a) $ 78.2 $ 78.2 $ — $ — International equities (a) 46.3 46.3 — — Fixed income (b) 163.3 163.3 — — Fixed income securities: U.S. Treasury securities 33.5 33.5 — — Other investments: Core property collective fund (c) 36.2 — 36.2 — Total pension plan assets $ 357.5 $ 321.3 $ 36.2 $ — (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, 2016 by asset category are as follows: Fair Value Measurements for Pension Plan Assets at December 31, 2016 $ in millions Market Value at December 31, 2016 Quoted prices Significant Significant Asset category (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: (c) Core property collective fund 33.1 — 33.1 — Common collective fund — — — — 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. 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 to the pension plan in each of the years ended December 31, 2017, 2016 and 2015. We expect to make contributions of $0.4 million to our SERP in 2018 to cover benefit payments. We made contributions of $7.5 million to our pension plan during January 2018 . Funding for the qualified Defined Benefit Pension Plan is based upon actuarially determined contributions that consider 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 99% . 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 $7.5 million in 2018 , which includes $2.2 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 2018 $ 28.4 2019 $ 28.2 2020 $ 27.9 2021 $ 27.6 2022 $ 27.3 2023 - 2027 $ 131.3 |
Equity
Equity | 12 Months Ended |
Dec. 31, 2017 | |
Entity Information [Line Items] | |
Equity | Equity Redeemable Preferred Stock of Subsidiary 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. DPL is also restricted from making dividend and tax sharing payments from DPL to AES per its 2017 ESP. This order restricts dividend payments from DPL to AES during the term of the ESP and restricts tax sharing payments from DPL to AES during the term of the DMR. Common Stock Effective on the Merger date, DPL's Amended Articles of Incorporation provided for 1,500 authorized common shares, of which one share is outstanding at December 31, 2017 . 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, 2017 , DPL’s leverage ratio was at 1.50 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, 2017 , 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, 2017 . 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 2016 and 2017, DP&L's equity ratio was 33% and its retained earnings balance was negative as of December 31, 2017. It is unknown what impact, if any, this will have on DP&L . Capital Contributions from AES In DP&L's approved six-year 2017 ESP, the PUCO imposed restrictions on DPL making dividend payments to its parent company, AES, during the term of the ESP, as well as on making tax-sharing payments to AES during the term of the DMR. The PUCO also required that existing tax payments owed by DPL to AES, and similar tax payments that accrue during the term of the DMR, be converted into equity investments in DPL . As such, AES agreed to make non-cash capital contributions of $97.1 million and waive the amount owed to it by DPL related to tax-sharing payments for current tax liabilities through December 31, 2017. See Note 9 – Income Taxes for additional information. |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Entity Information [Line Items] | |
Equity | Equity Redeemable Preferred Stock 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 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, 2017 . 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 first quarter of 2017 and the second and fourth quarters of 2016 and as of December 31, 2017, DP&L's equity ratio was 33% 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 In 2016, 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. Capital Contribution and Returns of Capital In 2017, DP&L received a $70.0 million capital contribution from its parent, DPL. In addition, DP&L made returns of capital payments of $39.0 million to DPL . In connection with Generation Separation, DP&L recorded $86.2 million as a return of capital. See Note 13 – Generation Separation for more information. In 2016, DP&L made a dividend payment of $70.0 million t o DPL . |
Contractual Obligations, Commer
Contractual Obligations, Commercial Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2017 | |
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, 2017 , DPL had $38.1 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 $0.9 million and $2.3 million at December 31, 2017 and 2016 , 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, 2017 , DP&L could be responsible for the repayment of 4.9% , or $70.6 million , of a $1,440.8 million debt obligation comprised of both fixed and variable rate securities with maturities between 2019 and 2040 . OVEC could also seek additional contributions from us to avoid a default in the event that other OVEC members defaulted on their respective OVEC obligations. At December 31, 2017 , 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, 2017 , these include: Payments due in: $ in millions Total Less than 2 - 3 4 - 5 More than Electricity purchase commitments $ 370.9 $ 178.5 $ 171.2 $ 21.2 $ — Coal and limestone contracts (a) $ 54.9 $ 54.9 $ — $ — $ — Purchase orders and other contractual obligations $ 73.0 $ 18.9 $ 27.1 $ 27.0 $ — (a) Total at DPL operated units. Electricity purchase commitments: DPL enters into long-term contracts for the purchase of electricity. In general, these contracts are subject to variable quantities or prices and are terminable only in limited circumstances. Coal contracts: DPL , through its subsidiary AES Ohio Generation, has entered into various long-term coal contracts to supply the coal requirements for the generating stations it operates. At December 31, 2017 , a majority of our future committed coal obligations are with one supplier . Some contract prices are subject to periodic adjustment and have features that limit price escalation in any given year. As a result of our planned shutdown of our Stuart and Killen generating stations, our commitments for coal and limestone do not extend past 2018. Purchase orders and other contractual obligations: At December 31, 2017 , DPL had various other contractual obligations including non-cancelable contracts to purchase goods and services with various terms and expiration dates. Due to uncertainty regarding the timing and payment of future obligations to the Service Company, and DPL's ability to terminate such obligations upon 90 days' notice, we have excluded such amounts in the contractual obligations table above. . 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, 2017 , cannot be reasonably determined. Environmental Matters DPL’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, the Ohio EPA or other authorities that require or will require substantial reductions in SO 2 , particulates, mercury, acid gases, NOx, and other air emissions. DPL installed emission control technology and is taking other measures to comply with required and anticipated reductions. As AES Ohio Generation is now operating these facilities, it is continuing to comply with these requirements; • Rules and future rules issued by the USEPA, the Ohio EPA or other authorities that require or will require reporting and reductions of GHGs; • Rules and future rules issued by the USEPA, the Ohio EPA or other authorities 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 OVEC which is recorded using the cost method of accounting under GAAP. At December 31, 2017 , DP&L could be responsible for the repayment of 4.9% , or $70.6 million , of a $1,440.8 million debt obligation comprised of both fixed and variable rate securities with maturities between 2019 and 2040 . OVEC could also seek additional contributions from us to avoid a default in the event that other OVEC members defaulted on their respective OVEC obligations. At December 31, 2017 , 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, 2017 , these include: Payments due in: $ in millions Total Less than 2 - 3 4 - 5 More than Electricity purchase commitments $ 370.9 $ 178.5 $ 171.2 $ 21.2 $ — Purchase orders and other contractual obligations $ 73.0 $ 18.9 $ 27.1 $ 27.0 $ — Electricity purchase commitments: DP&L enters into long-term contracts for the purchase of electricity. In general, these contracts are subject to variable quantities or prices and are terminable only in limited circumstances. Purchase orders and other contractual obligations: At December 31, 2017 , DP&L had various other contractual obligations including non-cancelable contracts to purchase goods and services with various terms and expiration dates. Due to uncertainty regarding the timing and payment of future obligations to the Service Company, and DP&L's ability to terminate such obligations upon 90 days' notice, we have excluded such amounts in the contractual obligations table above. 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, 2017 , 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; • Rules and future rules issued by the USEPA, the Ohio EPA or other authorities that require or will require reporting and reductions of GHGs; • Rules and future rules issued by the USEPA, the Ohio EPA or other authorities 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. 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, 2017 | |
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 2017 , 2016 and 2015 , 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 units 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 2017 , 2016 and 2015 was $0.4 million , $0.5 million and $0.5 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: Years ended December 31, $ in millions 2017 2016 2015 Transactions with the Service Company Charges for services provided $ 46.5 $ 42.8 $ 36.0 Charges to the Service Company $ 4.2 $ 4.6 $ 6.2 Transactions with other AES affiliates: Payments for health, welfare and benefit plans $ 15.4 $ 9.6 $ 15.5 Balances with related parties: At December 31, 2017 At December 31, 2016 Net payable to the Service Company $ (3.9 ) $ (2.0 ) Net payable to other AES affiliates $ (0.6 ) $ (2.5 ) 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 amounted to $0.3 million and $0.3 million at December 31, 2017 and 2016 , 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, 2017 and 2016 , 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 payable balance of $0.0 million at December 31, 2016, respectively, which is recorded in Accrued taxes on the accompanying Consolidated Balance Sheets. Effective with the approval of DP&L's 2017 ESP, DPL is restricted from making tax sharing payments to AES throughout the term of the DMR and amounts that would otherwise have been tax sharing liabilities are considered deemed capital contributions. See Note 9 – Income Taxes for more information. |
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 2017 , 2016 and 2015 , 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 units 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 2017 , 2016 and 2015 was $0.4 million , $0.5 million and $0.5 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 2017 2016 2015 DP&L revenues: Sales to DPLER (including MC Squared) (a) $ — $ — $ 303.3 DP&L Cost of revenues: Fuel and power purchased from AES Ohio Generation $ 5.4 $ 8.7 $ 5.2 DP&L Operation & Maintenance Expenses: Premiums charged for insurance services provided by MVIC (b) $ 3.1 $ 3.4 $ 3.2 Expense recoveries for services provided to DPLER (c) $ — $ — $ 2.4 Transactions with the Service Company: Charges for services provided $ 39.0 $ 38.7 $ 30.9 Charges to the Service Company $ 4.2 $ 4.5 $ 6.1 Transactions with other AES affiliates: Charges for health, welfare and benefit plans $ 14.3 $ 9.4 $ 14.8 Charges to affiliates for non-power goods or services (c) $ 3.7 $ 5.7 $ 4.9 Balances with related parties: At December 31, 2017 At December 31, 2016 Net payable to the Service Company $ (3.9 ) $ (2.0 ) Short-term loan with DPL $ — $ 5.0 Net receivable from / (payable) to other AES affiliates $ 4.8 $ (2.5 ) (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 charged by MVIC to DP&L . (c) In the normal course of business DP&L incurred and recorded expenses on behalf of DPL affiliates, which included 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 the affiliates 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 $8.6 million and $9.5 million at December 31, 2017 and 2016, respectively, which is recorded in Other current assets on the accompanying Balance Sheets. |
Business Segments
Business Segments | 12 Months Ended |
Dec. 31, 2017 | |
Segment Reporting Information [Line Items] | |
Business Segments | Business Segments DPL currently manages its business through two reportable operating segments, the 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 this measure 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 521,000 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 DP&L's investment in OVEC and the historical results of DP&L’s Beckjord and Hutchings Coal generating facilities, which were either closed or sold in prior periods. As these assets were not transferred to AES Ohio Generation, 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 the historical results of DP&L's electric generation business prior to Generation Separation. 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 coal-fired and peaking generating facilities and sells its generated energy and capacity into the PJM wholesale market. The 2015 Generation segment results also include sales to DPLER and to the T&D segment for SSO customers. 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, 2017 Revenues from external customers $ 718.9 $ 507.9 $ 10.1 $ — $ 1,236.9 Intersegment revenues 1.1 — 4.4 (5.5 ) — Total revenues $ 720.0 $ 507.9 $ 14.5 $ (5.5 ) $ 1,236.9 Depreciation and amortization $ 75.3 $ 20.9 $ 10.7 $ — $ 106.9 Fixed-asset impairment (Note 15) $ — $ 66.3 $ 109.5 $ — $ 175.8 Interest expense $ 30.5 $ 0.1 $ 79.5 $ — $ 110.1 Income / (loss) from continuing operations before income tax $ 88.5 $ (18.5 ) $ (189.9 ) $ — $ (119.9 ) Cash capital expenditures $ 85.6 $ 31.3 $ 4.6 $ — $ 121.5 Total assets (end of year) $ 1,689.4 $ 275.0 $ 468.0 $ (383.2 ) $ 2,049.2 $ 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 $ 25.4 $ 0.4 $ 82.2 $ (0.3 ) $ 107.7 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 $ 29.8 $ 2.9 $ 87.4 $ (0.3 ) $ 119.8 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. |
Fixed Asset Impairment
Fixed Asset Impairment | 12 Months Ended |
Dec. 31, 2017 | |
Entity Information [Line Items] | |
Fixed-asset Impairment | Fixed-asset Impairments During the years ended December 31, 2017 , 2016 and 2015 , DPL had the following fixed-asset impairments: Years ended December 31, $ in millions Measurement Date 2017 2016 2015 AES Ohio Generation peakers December 31, 2017 $ 109.4 $ — $ — Stuart March 31, 2017 39.1 — — Killen March 31, 2017 27.3 — — 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 — Total impairment loss $ 175.8 $ 859.0 $ — AES Ohio Generation peakers – In December 2017, AES Ohio Generation signed an agreement for the sale of its peaking and diesel generation assets. As a result of this transaction, DPL recognized an impairment of fixed assets in the amount of $109.4 million . Stuart and Killen, March 17, 2017 – On March 17, 2017, the Board of Directors of DP&L approved the retirement of the Stuart Station coal-fired and diesel-fired generating units and the Killen Station coal-fired generating unit and combustion turbine (collectively, the “Facilities”) on or before June 1, 2018. The co-owners of these facilities agreed with DP&L to proceed with this plan of retirement. We performed a long-lived asset impairment analysis and determined that the carrying amounts of the Facilities were not recoverable. The asset groups of Stuart Station and Killen Station were determined to have fair values of $3.3 million and $7.9 million , respectively, using the discounted cash flows under the income approach. As a result, we recognized asset impairment expense of $39.1 million and $27.3 million for Stuart Station and Killen Station, respectively. Additionally, as a result of the decision to retire the Facilities by June 1, 2018, we concluded that inventory at these Facilities is considered obsolete. As a result, we recognized a loss on disposal of $9.8 million and $6.4 million for Stuart Station and Killen Station inventories, respectively, during the first quarter of 2017, which is recorded in Loss on asset disposal in the Consolidated Statements of Operations. 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 the Miami Fort and Zimmer stations 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. We 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. |
Discontinued Operations
Discontinued Operations | 12 Months Ended |
Dec. 31, 2017 | |
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 recorded a gain on this transaction of $49.2 million in the first quarter of 2016. The gain included the impact of DPLER’s liability to DP&L that transferred with the sale on January 1, 2016. Operating activities related to DPLER have been reclassified to "Discontinued operations" in the Consolidated Statements of Operations for the years ended December 31, 2016 and 2015. The following table summarizes the revenues, cost of revenues, operating expenses and income tax of discontinued operations for the periods indicated: Years ended December 31, $ in millions 2016 2015 Revenues $ — $ 340.9 Cost of revenues — (307.0 ) Operating expenses (0.7 ) (22.5 ) Income / (loss) from discontinued operations before income tax (0.7 ) 11.4 Gain from disposal of discontinued operations 49.2 — Income tax expense / (benefit) from discontinued operations 19.2 (1.0 ) Income from discontinued operations $ 29.3 $ 12.4 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 and $35.8 million for the years ended December 31, 2016 and 2015, respectively. Cash flows from investing activities for discontinued operations were $75.5 million and $0.5 million for the years ended December 31, 2016 and 2015, respectively. All cash generated from discontinued operations was paid to DPL through dividends for all years presented. Assets and Liabilities Held-For-Sale and Dispositions Assets and liabilities held-for-sale On December 15, 2017, DPL and AES Ohio Generation entered into an asset purchase agreement with Kimura Power, LLC, as Buyer (“Kimura Power”), and, for certain limited purposes provided therein, Rockland Power Partners III, LP, as Guarantor, pursuant to which AES Ohio Generation will, subject to the terms and conditions in the asset purchase agreement, sell to Kimura Power the Peaker assets. The Peaker assets are being sold for $241.0 million in cash. The cash purchase price is subject to adjustments at closing based on working capital, capacity commitments and timing of the closing of the transaction. The sale transaction is subject to regulatory approvals and other closing conditions. The FERC approved this transaction on February 9, 2018. As a result of entering into the asset purchase agreement, DPL recognized aggregate impairment charges with respect to the Peaker assets of $109.4 million . For more information on these impairment charges, see Note 15 – Fixed-asset Impairments of Notes to DPL's Consolidated Financial Statements. The assets and liabilities related to the Peaker assets were classified as held-for-sale as of December 31, 2017, but the Peaker assets did not meet the criteria to be reported as discontinued operations. The following table summarizes the major classes of assets and liabilities classified as held-for-sale as of December 31, 2017: $ in millions December 31, 2017 Assets Accounts receivable, net $ 3.8 Inventories 7.6 Taxes applicable to subsequent years 4.9 Property, plant & equipment, net 233.7 Other assets 0.3 Total assets of the disposal group classified as held-for-sale in the balance sheet $ 250.3 Liabilities Accounts payable $ 3.9 Accrued taxes 3.6 Taxes payable 4.9 Asset retirement obligations 0.6 Other liabilities 0.2 Total liabilities of the disposal group classified as held-for-sale in the balance sheet $ 13.2 The Peaker assets' results of operations are reflected within continuing operations in the Consolidated Statements of Operations. The income from continuing operations before income tax for the Peaker assets was $16.9 million , $20.0 million and $23.9 million (excluding impairment charges of $109.4 million , $1.3 million and $0.0 million , respectively) for the years ended December 31, 2017, 2016, and 2015, respectively. The Peaker assets are included in the Generation segment. Dispositions On December 8, 2017, DPL and AES Ohio Generation completed the sale transaction of their entire undivided interest in the Miami Fort station and the Zimmer station to Dynegy Zimmer and Dynegy Miami Fort, indirect wholly-owned subsidiaries of Dynegy. On that date, AES Ohio Generation received $50.0 million in cash, plus an amount in cash equal to $20.1 million as an estimated purchase price adjustment based on estimated amounts of certain pre-closing inventories, pre-paid and other amounts, employment benefits, insurance premiums, property taxes and other payables, which will be subject to a customary post-closing reconciliation. This transaction resulted in a gain on sale of $14.0 million for the year ended December 31, 2017. Prior to the sale, the Miami Fort and Zimmer stations were included in the Generation segment. The results of operations of the Miami Fort and Zimmer stations are presented within continuing operations in the Consolidated Statements of Operations. The combined income / (loss) from continuing operations before income tax for the Miami Fort and Zimmer stations was $25.7 million (excluding gain on sale of $14.0 million ), $(13.5) million (excluding impairment charges of $294.1 million ) and $5.6 million for the years ended December 31, 2017, 2016, and 2015, respectively. |
Assets and Liabilities Held-For
Assets and Liabilities Held-For-Sale and Dispositions (Notes) | 12 Months Ended |
Dec. 31, 2017 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |
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 recorded a gain on this transaction of $49.2 million in the first quarter of 2016. The gain included the impact of DPLER’s liability to DP&L that transferred with the sale on January 1, 2016. Operating activities related to DPLER have been reclassified to "Discontinued operations" in the Consolidated Statements of Operations for the years ended December 31, 2016 and 2015. The following table summarizes the revenues, cost of revenues, operating expenses and income tax of discontinued operations for the periods indicated: Years ended December 31, $ in millions 2016 2015 Revenues $ — $ 340.9 Cost of revenues — (307.0 ) Operating expenses (0.7 ) (22.5 ) Income / (loss) from discontinued operations before income tax (0.7 ) 11.4 Gain from disposal of discontinued operations 49.2 — Income tax expense / (benefit) from discontinued operations 19.2 (1.0 ) Income from discontinued operations $ 29.3 $ 12.4 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 and $35.8 million for the years ended December 31, 2016 and 2015, respectively. Cash flows from investing activities for discontinued operations were $75.5 million and $0.5 million for the years ended December 31, 2016 and 2015, respectively. All cash generated from discontinued operations was paid to DPL through dividends for all years presented. Assets and Liabilities Held-For-Sale and Dispositions Assets and liabilities held-for-sale On December 15, 2017, DPL and AES Ohio Generation entered into an asset purchase agreement with Kimura Power, LLC, as Buyer (“Kimura Power”), and, for certain limited purposes provided therein, Rockland Power Partners III, LP, as Guarantor, pursuant to which AES Ohio Generation will, subject to the terms and conditions in the asset purchase agreement, sell to Kimura Power the Peaker assets. The Peaker assets are being sold for $241.0 million in cash. The cash purchase price is subject to adjustments at closing based on working capital, capacity commitments and timing of the closing of the transaction. The sale transaction is subject to regulatory approvals and other closing conditions. The FERC approved this transaction on February 9, 2018. As a result of entering into the asset purchase agreement, DPL recognized aggregate impairment charges with respect to the Peaker assets of $109.4 million . For more information on these impairment charges, see Note 15 – Fixed-asset Impairments of Notes to DPL's Consolidated Financial Statements. The assets and liabilities related to the Peaker assets were classified as held-for-sale as of December 31, 2017, but the Peaker assets did not meet the criteria to be reported as discontinued operations. The following table summarizes the major classes of assets and liabilities classified as held-for-sale as of December 31, 2017: $ in millions December 31, 2017 Assets Accounts receivable, net $ 3.8 Inventories 7.6 Taxes applicable to subsequent years 4.9 Property, plant & equipment, net 233.7 Other assets 0.3 Total assets of the disposal group classified as held-for-sale in the balance sheet $ 250.3 Liabilities Accounts payable $ 3.9 Accrued taxes 3.6 Taxes payable 4.9 Asset retirement obligations 0.6 Other liabilities 0.2 Total liabilities of the disposal group classified as held-for-sale in the balance sheet $ 13.2 The Peaker assets' results of operations are reflected within continuing operations in the Consolidated Statements of Operations. The income from continuing operations before income tax for the Peaker assets was $16.9 million , $20.0 million and $23.9 million (excluding impairment charges of $109.4 million , $1.3 million and $0.0 million , respectively) for the years ended December 31, 2017, 2016, and 2015, respectively. The Peaker assets are included in the Generation segment. Dispositions On December 8, 2017, DPL and AES Ohio Generation completed the sale transaction of their entire undivided interest in the Miami Fort station and the Zimmer station to Dynegy Zimmer and Dynegy Miami Fort, indirect wholly-owned subsidiaries of Dynegy. On that date, AES Ohio Generation received $50.0 million in cash, plus an amount in cash equal to $20.1 million as an estimated purchase price adjustment based on estimated amounts of certain pre-closing inventories, pre-paid and other amounts, employment benefits, insurance premiums, property taxes and other payables, which will be subject to a customary post-closing reconciliation. This transaction resulted in a gain on sale of $14.0 million for the year ended December 31, 2017. Prior to the sale, the Miami Fort and Zimmer stations were included in the Generation segment. The results of operations of the Miami Fort and Zimmer stations are presented within continuing operations in the Consolidated Statements of Operations. The combined income / (loss) from continuing operations before income tax for the Miami Fort and Zimmer stations was $25.7 million (excluding gain on sale of $14.0 million ), $(13.5) million (excluding impairment charges of $294.1 million ) and $5.6 million for the years ended December 31, 2017, 2016, and 2015, respectively. |
Generation Separation (Notes)
Generation Separation (Notes) | 12 Months Ended |
Dec. 31, 2017 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |
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 recorded a gain on this transaction of $49.2 million in the first quarter of 2016. The gain included the impact of DPLER’s liability to DP&L that transferred with the sale on January 1, 2016. Operating activities related to DPLER have been reclassified to "Discontinued operations" in the Consolidated Statements of Operations for the years ended December 31, 2016 and 2015. The following table summarizes the revenues, cost of revenues, operating expenses and income tax of discontinued operations for the periods indicated: Years ended December 31, $ in millions 2016 2015 Revenues $ — $ 340.9 Cost of revenues — (307.0 ) Operating expenses (0.7 ) (22.5 ) Income / (loss) from discontinued operations before income tax (0.7 ) 11.4 Gain from disposal of discontinued operations 49.2 — Income tax expense / (benefit) from discontinued operations 19.2 (1.0 ) Income from discontinued operations $ 29.3 $ 12.4 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 and $35.8 million for the years ended December 31, 2016 and 2015, respectively. Cash flows from investing activities for discontinued operations were $75.5 million and $0.5 million for the years ended December 31, 2016 and 2015, respectively. All cash generated from discontinued operations was paid to DPL through dividends for all years presented. Assets and Liabilities Held-For-Sale and Dispositions Assets and liabilities held-for-sale On December 15, 2017, DPL and AES Ohio Generation entered into an asset purchase agreement with Kimura Power, LLC, as Buyer (“Kimura Power”), and, for certain limited purposes provided therein, Rockland Power Partners III, LP, as Guarantor, pursuant to which AES Ohio Generation will, subject to the terms and conditions in the asset purchase agreement, sell to Kimura Power the Peaker assets. The Peaker assets are being sold for $241.0 million in cash. The cash purchase price is subject to adjustments at closing based on working capital, capacity commitments and timing of the closing of the transaction. The sale transaction is subject to regulatory approvals and other closing conditions. The FERC approved this transaction on February 9, 2018. As a result of entering into the asset purchase agreement, DPL recognized aggregate impairment charges with respect to the Peaker assets of $109.4 million . For more information on these impairment charges, see Note 15 – Fixed-asset Impairments of Notes to DPL's Consolidated Financial Statements. The assets and liabilities related to the Peaker assets were classified as held-for-sale as of December 31, 2017, but the Peaker assets did not meet the criteria to be reported as discontinued operations. The following table summarizes the major classes of assets and liabilities classified as held-for-sale as of December 31, 2017: $ in millions December 31, 2017 Assets Accounts receivable, net $ 3.8 Inventories 7.6 Taxes applicable to subsequent years 4.9 Property, plant & equipment, net 233.7 Other assets 0.3 Total assets of the disposal group classified as held-for-sale in the balance sheet $ 250.3 Liabilities Accounts payable $ 3.9 Accrued taxes 3.6 Taxes payable 4.9 Asset retirement obligations 0.6 Other liabilities 0.2 Total liabilities of the disposal group classified as held-for-sale in the balance sheet $ 13.2 The Peaker assets' results of operations are reflected within continuing operations in the Consolidated Statements of Operations. The income from continuing operations before income tax for the Peaker assets was $16.9 million , $20.0 million and $23.9 million (excluding impairment charges of $109.4 million , $1.3 million and $0.0 million , respectively) for the years ended December 31, 2017, 2016, and 2015, respectively. The Peaker assets are included in the Generation segment. Dispositions On December 8, 2017, DPL and AES Ohio Generation completed the sale transaction of their entire undivided interest in the Miami Fort station and the Zimmer station to Dynegy Zimmer and Dynegy Miami Fort, indirect wholly-owned subsidiaries of Dynegy. On that date, AES Ohio Generation received $50.0 million in cash, plus an amount in cash equal to $20.1 million as an estimated purchase price adjustment based on estimated amounts of certain pre-closing inventories, pre-paid and other amounts, employment benefits, insurance premiums, property taxes and other payables, which will be subject to a customary post-closing reconciliation. This transaction resulted in a gain on sale of $14.0 million for the year ended December 31, 2017. Prior to the sale, the Miami Fort and Zimmer stations were included in the Generation segment. The results of operations of the Miami Fort and Zimmer stations are presented within continuing operations in the Consolidated Statements of Operations. The combined income / (loss) from continuing operations before income tax for the Miami Fort and Zimmer stations was $25.7 million (excluding gain on sale of $14.0 million ), $(13.5) million (excluding impairment charges of $294.1 million ) and $5.6 million for the years ended December 31, 2017, 2016, and 2015, respectively. |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |
Discontinued Operations | Generation Separation On October 1, 2017, DP&L completed the transfer of its generating plants, the real property on which the generation plants and generation-related assets are sited, step-up transformers and other transmission plant assets used to interconnect with the electric transmission grid, fuel inventory, equipment inventory and spare parts, working capital, and other miscellaneous generation-related assets and liabilities ("Generation assets") to AES Ohio Generation. The transfer was completed as a contribution through an asset contribution agreement to a wholly-owned subsidiary of DP&L after which DP&L then distributed all of the outstanding equity in the subsidiary to DPL and then the subsidiary was merged into AES Ohio Generation. The following table summarizes the carrying amounts of DP&L's Generation assets that were transferred to AES Ohio Generation on October 1, 2017: $ in millions October 1, 2017 ASSETS Restricted cash $ 2.0 Accounts receivable, net 31.3 Inventories 42.0 Taxes applicable to subsequent years 1.8 Property, plant & equipment, net 87.0 Intangible assets, net 0.7 Other assets 15.5 Total assets $ 180.3 LIABILITIES Accounts payable $ 12.4 Accrued taxes (b) (3.9 ) Long-term debt (a) 0.3 Deferred taxes (b) (91.9 ) Pension, retiree and other benefits 9.6 Unamortized investment tax credit 15.1 Asset retirement obligations 126.3 Other liabilities 24.1 Total liabilities $ 92.0 Total accumulated other comprehensive income 2.1 Net assets transferred to AES Ohio Generation $ 86.2 (a) Long-term debt that transferred to AES Ohio Generation relates to capital leases. (b) Accrued taxes and deferred taxes transferred to AES Ohio Generation represent the tax asset position netted with liabilities on DP&L prior to Generation Separation. DP&L's generation business met the criteria to be classified as a discontinued operation, and, accordingly, the historical activity has been reclassified to "Discontinued operations" in the Statements of Operations for the years ended December 31, 2017 , 2016 and 2015 . Similarly, the assets and liabilities related to the generation business were classified as held-for-sale as of December 31, 2016. The following table summarizes the major categories of assets and liabilities at December 31, 2016, and the revenues, cost of revenues, operating and other expenses and income tax of discontinued operations for the periods indicated: December 31, $ in millions 2016 Restricted cash $ 29.0 Accounts receivable, net 34.9 Inventories 66.5 Taxes applicable to subsequent years 11.3 Property, plant & equipment, net 156.7 Intangible assets, net 0.9 Other assets 25.3 Total assets of the disposal group classified as held-for-sale in the balance sheets $ 324.6 Accounts payable $ 54.8 Accrued taxes 3.5 Long-term debt 13.4 Taxes payable 11.3 Deferred taxes (a) (120.7 ) Pension, retiree and other benefits 8.2 Unamortized investment tax credit 16.6 Asset retirement obligations 127.0 Other liabilities 43.6 Total liabilities of the disposal group classified as held-for-sale in the balance sheets $ 157.7 Years ended December 31, 2017 2016 2015 Revenues $ 358.4 $ 557.9 $ 901.6 Cost of revenues (191.6 ) (341.1 ) (698.3 ) Operating and other expenses (156.8 ) (202.0 ) (250.8 ) Fixed-asset impairment (66.3 ) (1,353.5 ) — Loss from discontinued operations (56.3 ) (1,338.7 ) (47.5 ) Income tax benefit from discontinued operations (15.9 ) (468.4 ) (23.9 ) Net loss from discontinued operations $ (40.4 ) $ (870.3 ) $ (23.6 ) (a) Deferred taxes represent the tax asset position netted with liabilities on DP&L prior to Generation Separation. Cash flows related to discontinued operations are included in the Statements of Cash Flows. Cash flows from operating activities for discontinued operations were $(10.4) million , $50.9 million and $138.7 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. Cash flows from investing activities for discontinued operations were $23.4 million , $(50.9) million and $(24.3) million for the years ended December 31, 2017 , 2016 and 2015 , respectively. Cash flows from financing activities for discontinued operations were $(13.0) million , $0.0 million and $(114.4) million for the years ended December 31, 2017 , 2016 and 2015 , respectively. The PUCO authorized DP&L to maintain long-term debt of $750 million or 75% of its rate base, whichever is greater, until January 1, 2018, or to file an application to explain why it would not achieve those metrics. Accordingly, $750.0 million of debt and the pro rata interest expense associated with that debt were allocated to continuing operations. All remaining debt and interest expense were included in discontinued operations above. The interest expense included in discontinued operations was $0.2 million , $0.5 million and $2.9 million for the years ended December 31, 2017, 2016 and 2015, respectively. |
Subsequent Events (Notes)
Subsequent Events (Notes) | 12 Months Ended |
Dec. 31, 2017 | |
Subsequent Event [Line Items] | |
Subsequent Events [Text Block] | Subsequent Event On February 26, 2018, DP&L and its co-owners of the retired Beckjord Facility agreed to transfer their interests in the retired Facility to a third party, including their obligations to remediate the Facility and its site, and the transfer occurred on that same date. As a result, DPL estimates that it will recognize aggregate pre-tax loss on disposal charges of approximately $11.7 million and that cash expenditures of $15.0 million in the aggregate will be made, inclusive of cash expenditures for the disposal charges. |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Subsequent Event [Line Items] | |
Subsequent Events [Text Block] | Subsequent Event On February 26, 2018, DP&L and its co-owners of the retired Beckjord Facility agreed to transfer their interests in the retired Facility to a third party, including their obligations to remediate the Facility and its site, and the transfer occurred on that same date. As a result, DP&L estimates that it will recognize aggregate pre-tax loss on disposal charges of approximately $12.4 million and that cash expenditures of $15.0 million in the aggregate will be made, inclusive of cash expenditures for the disposal charges. |
Schedule II Valuation And Quali
Schedule II Valuation And Qualifying Accounts | 12 Months Ended |
Dec. 31, 2017 | |
Schedule II Valuation And Qualifying Accounts | Schedule II DPL Inc. VALUATION AND QUALIFYING ACCOUNTS For each of the three years ended December 31, 2017 $ in thousands Description Balance at Beginning of Period Additions Deductions (a) Balance at End of Period Year ended December 31, 2017 Deducted from accounts receivable - Provision for uncollectible accounts (b) $ 1,159 $ 3,141 $ 3,247 $ 1,053 Deducted from deferred tax assets - Valuation allowance for deferred tax assets $ 38,266 $ 4,383 $ 6,321 $ 36,328 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 $ 39,874 $ — $ 1,608 $ 38,266 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 $ 40,713 $ 3,501 $ 4,340 $ 39,874 (a) Amounts written off, net of recoveries of accounts previously written off (b) Provision for uncollectible accounts related to DPL'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 year ended, December 31, 2015 Beginning balance $ 369 Additions 2,035 Deductions 2,291 Ending balance $ 113 |
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, 2017 $ in thousands Description Balance at Beginning of Period Additions Deductions (a) Balance at End of Period Year ended December 31, 2017 Deducted from accounts receivable - Provision for uncollectible accounts $ 1,159 $ 3,141 $ 3,247 $ 1,053 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 (a) Amounts written off, net of recoveries of accounts previously written off |
Overview and Summary of Signi30
Overview and Summary of Significant Accounting Policies (Policy) | 12 Months Ended |
Dec. 31, 2017 | |
Significant Accounting Policies [Line Items] | |
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 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 521,000 customers located in West Central Ohio. DP&L is required to procure and provide retail SSO electric service to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio. Since January 2016, DP&L has been sourcing 100% of the generation for its SSO customers through a competitive bid process. Through September 30, 2017, DP&L owned undivided interests in five coal-fired power stations and multiple peaking electric generating facilities as well as numerous transmission facilities. On October 1, 2017, the DP&L -owned generating facilities were transferred to AES Ohio Generation, an affiliate of DP&L and wholly-owned subsidiary of DPL , through an asset contribution agreement to a subsidiary that was merged into AES Ohio Generation. Also, Stuart Station Unit 1 was retired on October 1, 2017. 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. Through the date of Generation Separation, DP&L sold energy and capacity into the wholesale market. 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 coal-fired and 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 wholly owns each of its subsidiaries. On December 8, 2017, AES Ohio Generation completed the sale of the Miami Fort and Zimmer stations to subsidiaries of Dynegy in accordance with an asset purchase agreement dated April 21, 2017. In addition, on December 15, 2017, AES Ohio Generation entered into an asset purchase agreement for the sale of its Peaker assets to Kimura Power, LLC. 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. 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 1,060 people at January 31, 2018 , of which 660 were employed by DP&L . Approximately 60% of all DPL employees are under a collective bargaining agreement. The current agreement, after initially being extended, expired on January 31, 2018. Under national labor law, all the terms and conditions of the expired agreement continue indefinitely, with a few exceptions. Notably, the union has the right to strike and DP&L and AES Ohio Generation each have the right to lock out employees. We are continuing to negotiate with the union to enter into a new collective bargaining agreement. Currently, we are unable to predict the eventual outcome of these negotiations and have contingency plans to continue our operations. If we are not able to reach an agreement on terms favorable to us or to effectively implement our plans in the event that agreement is not reached, our results of operations, financial position and cash flows could be adversely impacted. |
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. AES Ohio Generation's undivided ownership interests in certain coal-fired generating stations are included in the financial statements at amortized cost, net of subsequent impairments. Operating revenues and expenses are included on a pro rata basis in the corresponding lines in the Consolidated Statement of Operations. DP&L has undivided ownership interests in numerous transmission facilities. These undivided interests in jointly-owned facilities are accounted for on a pro rata basis in the Consolidated Financial Statements. 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. |
Discontinued Operations, Policy [Policy Text Block] | Discontinued operations reporting occurs only when the disposal of a business or a group of businesses represents a strategic shift that has (or will have) a major effect on our operations and financial results. We report financial results for discontinued operations separately from continuing operations to distinguish the financial impact of disposal transactions from ongoing operations. Prior period amounts in the statement of operations and balance sheet are retrospectively revised to reflect the businesses determined to be discontinued operations. The cash flows of businesses that are determined to be discontinued operations are included within the relevant categories within operating, investing and financing activities on the face of the Statements of Cash Flows. Transactions between the businesses determined to be discontinued operations and businesses that are expected to continue to exist after the disposal are not eliminated to appropriately reflect the continuing operations and balances held-for-sale. The results of discontinued operations include any gain or loss recognized on closing or adjustment of the carrying amount to fair value. See Note 16 – Discontinued Operations for further 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. |
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 Consolidated 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. 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 | 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 $2.3 million , $2.8 million and $2.0 million in the years ended December 31, 2017 , 2016 and 2015 , respectively. For unregulated generation property, cost includes direct labor and material, allocable overhead expenses and interest capitalized during construction per the provisions of GAAP related 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 Impairments 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 5.0% in 2017 , 6.1% in 2016 and 4.4% in 2015 . Depreciation expense was $100.1 million , $124.6 million and $125.6 million for the years ended December 31, 2017 , 2016 and 2015 , 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, net of reserves, and include coal, limestone, oil and gas used for electric generation, and materials and supplies used for utility operations. |
Intangibles | Software is amortized over seven years. A mortization expense was $6.8 million , $7.7 million and $9.0 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. The estimated amortization expense of this internal-use software over the next five years is $17.2 million ( $7.2 million in 2018, $4.2 million in 2019, $2.7 million in 2020, $1.7 million in 2021 and $1.4 million in 2022 ). |
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. |
Assets and liabilities held-for-sale, policy [Policy Text Block] | A business classified as held-for-sale is reflected on the balance sheet at the lower of its carrying amount or estimated fair value less cost to sell. A loss is recognized if the carrying amount of the business exceeds its estimated fair value less cost to sell. This loss is limited to the carrying value of long lived assets until the completion of the sale, at which point, any additional loss is recognized. If the fair value of the business subsequently exceeds the carrying amount while the business is still held-for-sale, any impairment expense previously recognized will be reversed up to the lower of the previously recognized expense or the subsequent excess. Assets and liabilities related to a business classified as held-for-sale are segregated in the current balance sheet in the period in which the business is classified as held-for-sale. Assets and liabilities of held-for-sale businesses are classified as current when they are expected to be disposed of within twelve months. Transactions between the business held-for-sale and businesses that are expected to continue to exist after the disposal are not eliminated to appropriately reflect the continuing operations and balances held-for-sale. See Note 17 – Assets and Liabilities Held-For-Sale and Dispositions for further information. |
Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities | 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, 2017 , 2016 and 2015 , were $49.4 million , $50.9 million and $49.9 million , respectively. |
Cash and Cash Equivalents | 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 and cash collected under the DMR which is restricted to pay debt obligations at DPL and DP&L and position DP&L to modernize and/or maintain its transmission and distribution infrastructure. |
Financial Derivatives | 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 | 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. Insurance and Claims Costs on DPL’s Consolidated Balance Sheets associated with MVIC include estimated liabilities of approximately $3.0 million and $5.4 million at December 31, 2017 and 2016 , respectively. DPL has estimated liabilities for medical, life, disability, and other reserves for claims costs below certain coverage thresholds of third-party providers of approximately $11.9 million and $10.9 million at December 31, 2017 and 2016 , 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 DPL 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, that would otherwise be recognized in AOCI, recorded as a regulatory asset as this 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 postretirement benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postretirement 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. Consistent with the requirements of FASC 715, we apply a disaggregated discount rate approach for determining service cost and interest cost for our defined benefit pension plans and postretirement plans. 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 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. See Note 10 – Benefit Plans for more information. |
Related Party Transactions | 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. |
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 2016-09, 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. January 1, 2017. 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. New Accounting Standards Issued But Not Yet Effective 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220), Reclassification of Certain Tax Effects from AOCI This amendment allows a reclassification of the stranded tax effects resulting from the implementation of the Tax Cuts and Jobs Act from AOCI to retained earnings. Because this amendment only relates to the reclassification of the income tax effects of the Tax Cuts and Jobs Act, the underlying guidance that requires that the effect of a change in tax laws or rates be included in income from continuing operations is not affected. January 1, 2019. Early adoption is permitted. We are currently evaluating the impact of adopting the standard on our consolidated financial statements. 2017-12, Derivatives and Hedging (Topic 815): Targeted improvements to Accounting for Hedging Activities The standard updates the hedge accounting model to expand the ability to hedge nonfinancial and financial risk components, reduce complexity, and ease certain documentation and assessment requirements. When facts and circumstances are the same as at the previous quantitative test, a subsequent quantitative effectiveness test is not required. The standard also eliminates the requirement to separately measure and report hedge ineffectiveness. For cash flow hedges, this means that the entire change in the fair value of a hedging instrument will be recorded in other comprehensive income and amounts deferred will be reclassified to earnings in the same income statement line as the hedged item. January 1, 2019. Early adoption is permitted. We are currently evaluating the impact of adopting the standard on our consolidated financial statements. 2017-08, Receivables - Nonrefundable Fees and Other Costs (Subtopic 310-20): Premium Amortization on Purchased Callable Debt Securities This standard shortens the period of amortization for the premium on certain callable debt securities to the earliest call date. January 1, 2019. Early adoption is permitted. We are currently evaluating the impact of adopting the standard on our consolidated financial statements. 2017-07, Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost This standard changes the presentation of non-service cost associated with defined benefit plans and updates the guidance so that only the service cost component will be eligible for capitalization. January 1, 2018. We expect the adoption of this standard to result in a reclassification of non-service pension costs from Operating expenses to Other expense of $1.9 million and $1.8 million in 2017 and 2016, respectively. Accounting Standard Description Date of Adoption Effect on the financial statements upon adoption 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. January 1, 2018 We expect the adoption of this standard to result in a reclassification from "Net cash used in investing activities" to "Net increase / (decrease) in cash" of $27.1 million and ($11.8) million in 2017 and 2016, respectively. 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. 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. 2016-02, Leases (Topic 842) See discussion of the ASU below. January 1, 2019. 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 ASUs below. January 1, 2018. We will adopt the standards on January 1, 2018; see below for the evaluation of the impact of its adoption on the 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 replaces most existing revenue recognition guidance in GAAP. 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. 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. At this time, we do not expect any significant impact on our financial systems or a material change to controls as a result of the implementation of the new revenue recognition standard. We are assessing the standard on a contract-by-contract basis applying the interpretations reached during 2017 on key issues. This includes the application of the practical expedient for measuring progress towards 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 allocate variable consideration to one or more, but not all, distinct goods or services promised in a series of distinct goods or services that forms part of a single performance obligation. Additionally, we have been working on the application of the standard to contracts that are under the scope of Service Concession Arrangements (Topic 853) and assessing the gross versus net presentation for spot energy sale and purchases. Through this assessment to date, we have not identified any situations where revenue recognized under FASC 606 could differ from that recognized under FASC 605 or where the presentation of sales to and purchases from the spot markets will change. Given the limited impact, we expect to use the modified retrospective approach. |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Significant Accounting Policies [Line Items] | |
Description of Business | DP&L is a public utility incorporated in 1911 under the laws of Ohio. Beginning in 2001, Ohio law gave 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 521,000 customers located in West Central Ohio. DP&L is required to procure and provide retail SSO electric service to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio. Since January 2016, DP&L has been sourcing 100% of the generation for its SSO customers through a competitive bid process. Through September 30, 2017, DP&L owned undivided interests in five coal-fired power stations and multiple peaking electric generating facilities as well as numerous transmission facilities. On October 1, 2017, the DP&L -owned generating facilities were transferred to AES Ohio Generation, an affiliate of DP&L , through an asset contribution agreement to a subsidiary that was merged into AES Ohio Generation. As a result of Generation Separation, DP&L now only has one reportable segment, Transmission and Distribution. In addition to DP&L's electric transmission and distribution businesses, the Transmission and Distribution segment includes revenues and costs associated with DP&L's investment in OVEC and the historical results of DP&L’s Beckjord and Hutchings Coal generating facilities, which were either closed or sold in prior periods. Principal industries located in DP&L’s service territory include automotive, food processing, paper, plastic, manufacturing and defense. DP&L's sales reflect the general economic conditions, seasonal weather patterns of the area and the market price of electricity. Through the date of Generation Separation, DP&L sold energy and capacity into the wholesale market. 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. DP&L employed 660 people at January 31, 2018 . Approximately 53% of all employees are under a collective bargaining agreement. The current agreement, after initially being extended, expired on January 31, 2018. Under national labor law, all the terms and conditions of the expired agreement continue indefinitely, with a few exceptions. Notably, the union has the right to strike and DP&L has the right to lock out employees. We are continuing to negotiate with the union to enter into a new collective bargaining agreement. Currently, we are unable to predict the eventual outcome of these negotiations and have contingency plans to continue our operations. If we are not able to reach an agreement on terms favorable to us or to effectively implement our plans in the event that agreement is not reached, our results of operations, financial position and cash flows could be adversely impacted. |
Financial Statement Presentation | DP&L does not have any subsidiaries. DP&L has undivided ownership interests in numerous transmission facilities. These undivided interests in jointly-owned facilities are accounted for on a pro rata basis in the Financial Statements. In the fourth quarter of 2017, DP&L entered into an agreement with two other Ohio utilities to eliminate the co-ownership relationship they have had with respect to certain transmission facilities (transmission lines and substations) located in Ohio. See Note 4 – Property, Plant and Equipment for more information. 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. In 2017, we have reclassified the presentation of the December 2016 dividend payment of $70.0 million which was originally recorded as a charge to Accumulated deficit and is now presented as a charge to Other paid-in capital. This reclassification was to prospectively correct an immaterial error. |
Discontinued Operations, Policy [Policy Text Block] | Discontinued operations reporting occurs only when the disposal of a business or a group of businesses represents a strategic shift that has (or will have) a major effect on our operations and financial results. We report financial results for discontinued operations separately from continuing operations to distinguish the financial impact of disposal transactions from ongoing operations. Prior period amounts in the statement of operations and balance sheet are retrospectively revised to reflect the businesses determined to be discontinued operations. The cash flows of businesses that are determined to be discontinued operations are included within the relevant categories within operating, investing and financing activities on the face of the Statements of Cash Flows. Transactions between the businesses determined to be discontinued operations and businesses that are expected to continue to exist after the disposal are not eliminated to appropriately reflect the continuing operations and balances held-for-sale. The results of discontinued operations include any gain or loss recognized on closing or adjustment of the carrying amount to fair value. See Note 13 – Generation Separation for further information. Generation Separation With the transfer of DP&L's generation assets to an affiliate (see Note 13 – Generation Separation ), DP&L's generation business is presented as a discontinued operation and the operating activities have been reclassified to "Discontinued operations" in the Statements of Operations for the years ended December 31, 2017, 2016 and 2015 and in the footnotes to the financial statements. The assets and liabilities related to the discontinued operations have been reclassified to held-for-sale in the balance sheet as of December 31, 2016. The PUCO authorized DP&L to maintain long-term debt of $750 million or 75% of its rate base, whichever is greater, until January 1, 2018, or to file an application to explain why it would not achieve those metrics. Accordingly, $750.0 million of debt and the pro rata interest expense associated with that debt were allocated to continuing operations. All remaining debt and interest expense were included in discontinued operations above. The interest expense included in discontinued operations was $0.2 million , $0.5 million and $2.9 million for the years ended December 31, 2017, 2016 and 2015, respectively. |
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 | 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. 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. |
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 | We record our ownership share of our undivided interest in jointly-owned transmission and distribution property 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 $2.0 million , $2.7 million and $2.0 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. 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 transmission and distribution assets, straight-line depreciation is applied monthly on an average composite basis using group rates. For DP&L’s transmission and distribution assets, straight-line depreciation is applied on an average annual composite basis using group rates that approximated 3.4% in 2017 , 4.6% in 2016 and 2.5% in 2015 . Depreciation expense was $69.6 million , $64.3 million and $64.3 million for the years ended December 31, 2017 , 2016 and 2015 , 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 materials and supplies used for utility operations. |
Intangibles | Software is amortized over seven years. A mortization expense was $5.7 million , $6.7 million and $7.2 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. The estimated amortization expense of this internal-use software over the next five years is $10.7 million ( $5.1 million in 2018, $3.1 million in 2019, $1.6 million in 2020, $0.6 million in 2021 and $0.3 million in 2022 ). |
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. DP&L files 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. |
Assets and liabilities held-for-sale, policy [Policy Text Block] | A business classified as held-for-sale is reflected on the balance sheet at the lower of its carrying amount or estimated fair value less cost to sell. A loss is recognized if the carrying amount of the business exceeds its estimated fair value less cost to sell. This loss is limited to the carrying value of long lived assets until the completion of the sale, at which point, any additional loss is recognized. If the fair value of the business subsequently exceeds the carrying amount while the business is still held-for-sale, any impairment expense previously recognized will be reversed up to the lower of the previously recognized expense or the subsequent excess. Assets and liabilities related to a business classified as held-for-sale are segregated in the current balance sheet in the period in which the business is classified as held-for-sale. Assets and liabilities of held-for-sale businesses are classified as current when they are expected to be disposed of within twelve months. Transactions between the business held-for-sale and businesses that are expected to continue to exist after the disposal are not eliminated to appropriately reflect the continuing operations and balances held-for-sale. See Note 13 – Generation Separation for further information. |
Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities | The amounts for the years ended December 31, 2017 , 2016 and 2015 were $49.4 million , $50.9 million and $49.9 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 relates to cash collected under the DMR which is restricted to pay debt obligations at DPL and DP&L and position DP&L to modernize and/or maintain its transmission and distribution infrastructure. |
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. We use forward contracts to reduce our exposure to changes in interest rates. 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 $4.4 million and $3.9 million at December 31, 2017 and 2016 , 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 postretirement benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postretirement 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. Consistent with the requirements of FASC 715, we apply a disaggregated discount rate approach for determining service cost and interest cost for our defined benefit pension plans and postretirement plans. 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 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. 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 2016-09, 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. January 1, 2017. 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. New Accounting Standards Issued But Not Yet Effective 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220), Reclassification of Certain Tax Effects from AOCI This amendment allows a reclassification of the stranded tax effects resulting from the implementation of the Tax Cuts and Jobs Act from AOCI to retained earnings. Because this amendment only relates to the reclassification of the income tax effects of the Tax Cuts and Jobs Act, the underlying guidance that requires that the effect of a change in tax laws or rates be included in income from continuing operations is not affected. January 1, 2019. Early adoption is permitted. We are currently evaluating the impact of adopting the standard on our financial statements. 2017-12, Derivatives and Hedging (Topic 815): Targeted improvements to Accounting for Hedging Activities The standard updates the hedge accounting model to expand the ability to hedge nonfinancial and financial risk components, reduce complexity, and ease certain documentation and assessment requirements. When facts and circumstances are the same as at the previous quantitative test, a subsequent quantitative effectiveness test is not required. The standard also eliminates the requirement to separately measure and report hedge ineffectiveness. For cash flow hedges, this means that the entire change in the fair value of a hedging instrument will be recorded in other comprehensive income and amounts deferred will be reclassified to earnings in the same income statement line as the hedged item. January 1, 2019. Early adoption is permitted. We are currently evaluating the impact of adopting the standard on our financial statements. 2017-08, Receivables - Nonrefundable Fees and Other Costs (Subtopic 310-20): Premium Amortization on Purchased Callable Debt Securities This standard shortens the period of amortization for the premium on certain callable debt securities to the earliest call date. January 1, 2019. Early adoption is permitted. We are currently evaluating the impact of adopting the standard on our financial statements. 2017-07, Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost This standard changes the presentation of non-service cost associated with defined benefit plans and updates the guidance so that only the service cost component will be eligible for capitalization. January 1, 2018. We expect the adoption of this standard to result in a reclassification of non-service pension costs from Operating expenses to Other expense of $7.2 million and $7.8 million in 2017 and 2016, respectively. 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. January 1, 2018 We expect the adoption of this standard to result in a reclassification from "Net cash used in investing activities" to "Net increase / (decrease) in cash" of $26.6 million and ($11.9) million in 2017 and 2016, respectively. Accounting Standard Description Date of Adoption Effect on the financial statements upon adoption 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. 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. 2016-02, Leases (Topic 842) See discussion of the ASU below. January 1, 2019. 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 ASUs below. January 1, 2018. We will adopt the standards on January 1, 2018; see below for the evaluation of the impact of its adoption on the 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 replaces most existing revenue recognition guidance in GAAP. 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. 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. At this time, we do not expect any significant impact on our financial systems or a material change to controls as a result of the implementation of the new revenue recognition standard. We are assessing the standard on a contract-by-contract basis applying the interpretations reached during 2017 on key issues. This includes the application of the practical expedient for measuring progress towards 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 allocate variable consideration to one or more, but not all, distinct goods or services promised in a series of distinct goods or services that forms part of a single performance obligation. Additionally, we have been working on the application of the standard to contracts that are under the scope of Service Concession Arrangements (Topic 853) and assessing the gross versus net presentation for spot energy sale and purchases. Through this assessment to date, we have not identified any situations where revenue recognized under FASC 606 could differ from that recognized under FASC 605 or where the presentation of sales to and purchases from the spot markets will change. Given the limited impact, we expect to use the modified retrospective approach. We are continuing to work with various non-authoritative industry groups and continue to monitor the FASB and Transition Resource Group activity as we finalize our accounting policy on these and other industry-specific interpretive issues. ASU 2016-02 and its subsequent corresponding updates require lessees to recognize assets and liabilities for most leases but recognize expenses in a manner similar to today’s accounting. For Lessors, the guidance modifies the lease classification criteria and the accounting for sales-type and direct financing leases. The guidance also eliminates today’s real estate-specific provisions. The standard requires modified retrospective adoption at the beginning of the earliest comparative period presented in the financial statements (January 1, 2017). The FASB proposed amending the standard to give another option for transition. The proposed transition method would allow entities to not apply the new lease standard in the comparative periods presented in their financial statements in the year of adoption. Under the proposed transition method, the entity would apply the transition provisions on January 1, 2019 (i.e., the effective date). At transition, lessees and lessors are permitted to make an election to apply a package of practical expedients that allow them not to reassess: (1) whether any expired or existing contracts are or contain leases, (2) lease classification for any expired or existing leases, and (3) whether initial direct costs for any expired or existing leases qualify for capitalization under FASC 842. These three practical expedients must be elected as a package and must be consistently applied to all leases. Furthermore, entities are also permitted to make an election to use hindsight when determining lease term and entities can elect to use hindsight when assessing the impairment of right-of-use assets. We have established a task force focused on the identification of contracts that would be under the scope of the new standard and on the assessment and measurement of the right-of-use asset and related liability. Additionally, the implementation team has been working on the identification and selection of a lease accounting system that would support the implementation and the subsequent accounting. The implementation team is in the process of evaluating changes to our business processes, systems and controls to support recognition and disclosure under the new standard. As we have preliminarily concluded that at transition we would be using the package of practical expedients, the main impact expected as of the effective date is the recognition of the right to use asset and the related liability in the financial statements for all those contracts that contain a lease and for which we are the lessee. However, income statement presentation and the expense recognition pattern is not expected to change. Under FASC 842, it is expected that fewer contracts will contain a lease. However, due to the elimination of today's real estate-specific guidance and changes to certain lessor classification criteria, more leases will qualify as sales-type leases and direct financing leases. Under these two models, a lessor will derecognize the asset and will recognize a lease receivable. According to FASC 842, the lease receivable does not include variable payments that depend on the use of the asset (e.g. Mwh produced by a facility). Therefore, the lease receivable could be lower than the carrying amount of the underlying asset at lease commencement. In such circumstances, the difference between the initially recognized lease receivable and the carrying amount of the underlying is recognized as a selling loss at lease commencement. We are assessing situations for which this guidance would apply. |
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, 2017 and 2016 , 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, 2017 and December 31, 2016 , 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. |
Generation Separation (Policies
Generation Separation (Policies) | 12 Months Ended |
Dec. 31, 2017 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |
Discontinued Operations, Policy [Policy Text Block] | Discontinued operations reporting occurs only when the disposal of a business or a group of businesses represents a strategic shift that has (or will have) a major effect on our operations and financial results. We report financial results for discontinued operations separately from continuing operations to distinguish the financial impact of disposal transactions from ongoing operations. Prior period amounts in the statement of operations and balance sheet are retrospectively revised to reflect the businesses determined to be discontinued operations. The cash flows of businesses that are determined to be discontinued operations are included within the relevant categories within operating, investing and financing activities on the face of the Statements of Cash Flows. Transactions between the businesses determined to be discontinued operations and businesses that are expected to continue to exist after the disposal are not eliminated to appropriately reflect the continuing operations and balances held-for-sale. The results of discontinued operations include any gain or loss recognized on closing or adjustment of the carrying amount to fair value. See Note 16 – Discontinued Operations for further information. |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |
Discontinued Operations, Policy [Policy Text Block] | Discontinued operations reporting occurs only when the disposal of a business or a group of businesses represents a strategic shift that has (or will have) a major effect on our operations and financial results. We report financial results for discontinued operations separately from continuing operations to distinguish the financial impact of disposal transactions from ongoing operations. Prior period amounts in the statement of operations and balance sheet are retrospectively revised to reflect the businesses determined to be discontinued operations. The cash flows of businesses that are determined to be discontinued operations are included within the relevant categories within operating, investing and financing activities on the face of the Statements of Cash Flows. Transactions between the businesses determined to be discontinued operations and businesses that are expected to continue to exist after the disposal are not eliminated to appropriately reflect the continuing operations and balances held-for-sale. The results of discontinued operations include any gain or loss recognized on closing or adjustment of the carrying amount to fair value. See Note 13 – Generation Separation for further information. Generation Separation With the transfer of DP&L's generation assets to an affiliate (see Note 13 – Generation Separation ), DP&L's generation business is presented as a discontinued operation and the operating activities have been reclassified to "Discontinued operations" in the Statements of Operations for the years ended December 31, 2017, 2016 and 2015 and in the footnotes to the financial statements. The assets and liabilities related to the discontinued operations have been reclassified to held-for-sale in the balance sheet as of December 31, 2016. The PUCO authorized DP&L to maintain long-term debt of $750 million or 75% of its rate base, whichever is greater, until January 1, 2018, or to file an application to explain why it would not achieve those metrics. Accordingly, $750.0 million of debt and the pro rata interest expense associated with that debt were allocated to continuing operations. All remaining debt and interest expense were included in discontinued operations above. The interest expense included in discontinued operations was $0.2 million , $0.5 million and $2.9 million for the years ended December 31, 2017, 2016 and 2015, respectively. |
Supplemental Financial Inform32
Supplemental Financial Information (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Supplemental Financial Information [Line Items] | |
Supplemental Financial Information | December 31, $ in millions 2017 2016 Accounts receivable, net Unbilled revenue $ 18.0 $ 43.0 Customer receivables 57.8 73.9 Amounts due from partners in jointly-owned stations 19.1 12.7 Other 4.9 6.7 Provisions for uncollectible accounts (1.1 ) (1.2 ) Total accounts receivable, net $ 98.7 $ 135.1 Inventories, at average cost Fuel and limestone $ 15.5 $ 38.9 Plant materials and supplies 8.5 36.6 Other 0.5 1.7 Total inventories, at average cost $ 24.5 $ 77.2 |
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, 2017 , 2016 and 2015 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 2017 2016 2015 Gains and losses on Available-for-sale securities activity (Note 5): Other deductions $ (0.1 ) $ — $ — Income tax expense / (benefit) from continuing operations — — — Net of income taxes (0.1 ) — — Gains and losses on cash flow hedges (Note 6): Interest expense (1.0 ) (1.0 ) (1.1 ) Revenues (15.2 ) (55.3 ) (18.7 ) Net purchased power cost 3.8 9.9 4.4 Total before income taxes (12.4 ) (46.4 ) (15.4 ) Income tax expense / (benefit) from continuing operations 4.4 16.7 5.4 Net of income taxes (8.0 ) (29.7 ) (10.0 ) Amortization of defined benefit pension items (Note 10): Operation and maintenance 1.5 1.6 0.4 Income tax expense / (benefit) from continuing operations (0.5 ) (0.6 ) (0.2 ) Net of income taxes 1.0 1.0 0.2 Total reclassifications for the period, net of income taxes $ (7.1 ) $ (28.7 ) $ (9.8 ) |
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, 2017 and 2016 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, 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 Other comprehensive income / (loss) before reclassifications 0.5 9.6 (2.5 ) 7.6 Amounts reclassified from accumulated other comprehensive income / (loss) (0.1 ) (8.0 ) 1.0 (7.1 ) Net current period other comprehensive income / (loss) 0.4 1.6 (1.5 ) 0.5 Balance at December 31, 2017 $ 1.0 $ 14.7 $ (14.9 ) $ 0.8 |
Schedule of Other Operating Cost and Expense, by Component [Table Text Block] | Operating expenses - other generally includes gains or losses on asset sales or dispositions, insurance recoveries, gains or losses on the sale of businesses and other expense or income from miscellaneous transactions. The components are summarized as follows: Years ended December 31, $ in millions 2017 2016 2015 Write-off of plant materials and supplies inventories $ 16.2 $ — $ — Gain on sale of business (14.0 ) — — Insurance recoveries (8.7 ) (0.7 ) — Loss / (gain) on disposition of property — (0.1 ) 0.4 Other (0.1 ) 0.7 — Net other expense / (income) $ (6.6 ) $ (0.1 ) $ 0.4 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Supplemental Financial Information [Line Items] | |
Supplemental Financial Information | Supplemental Financial Information December 31, $ in millions 2017 2016 Accounts receivable, net Unbilled revenue $ 18.0 $ 43.0 Customer receivables 44.2 45.9 Amounts due from partners in jointly-owned stations 5.0 4.0 Other 4.7 8.1 Provisions for uncollectible accounts (1.1 ) (1.2 ) Total accounts receivable, net $ 70.8 $ 99.8 Inventories, at average cost Plant materials and supplies $ 6.9 $ 6.9 Other 0.4 2.4 Total inventories, at average cost $ 7.3 $ 9.3 |
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, 2017 , 2016 and 2015 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 2017 2016 2015 Gains and losses on Available-for-sale securities activity (Note 5): Other deductions $ (0.1 ) $ — $ — Income tax expense from continuing operations — — — Net of income taxes (0.1 ) — — Gains and losses on cash flow hedges (Note 6): Interest expense (0.9 ) (1.0 ) (1.1 ) Income tax expense from continuing operations 0.2 0.2 0.2 Loss from discontinued operations (8.5 ) (45.4 ) (14.3 ) Income tax benefit from discontinued operations 3.0 16.2 5.4 Net of income taxes (6.2 ) (30.0 ) (9.8 ) Amortization of defined benefit pension items (Note 9): Operation and maintenance 6.8 7.7 5.6 Income tax expense from continuing operations (2.3 ) (1.8 ) (1.9 ) Net of income taxes 4.5 5.9 3.7 Total reclassifications for the period, net of income taxes $ (1.8 ) $ (24.1 ) $ (6.1 ) |
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, 2017 and 2016 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, 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 ) Other comprehensive income / (loss) before reclassifications 0.5 12.4 (2.7 ) 10.2 Amounts reclassified from accumulated other comprehensive income / (loss) (0.1 ) (6.2 ) 4.5 (1.8 ) Net current period other comprehensive income 0.4 6.2 1.8 8.4 Transfer of generation assets to subsidiary of parent — (2.1 ) — (2.1 ) Balance at December 31, 2017 $ 1.1 $ 1.4 $ (38.7 ) $ (36.2 ) |
Regulatory Assets and Liabili33
Regulatory Assets and Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Schedule of Regulatory Assets and Liabilities | The following table presents DPL’s Regulatory assets and liabilities: Type of Recovery Amortization Through December 31, $ in millions 2017 2016 Regulatory assets, current: Undercollections to be collected through rate riders A/B 2018 $ 23.9 $ 0.1 Total regulatory assets, current 23.9 0.1 Regulatory assets, non-current: Pension benefits B Ongoing 92.4 97.6 Deferred recoverable income taxes B/C Ongoing — 35.9 Unrecovered OVEC charges D Undetermined 27.8 21.0 Fuel costs B 2020 9.3 15.4 Regulatory compliance costs B 2020 9.2 12.4 Rate case costs B Undetermined 8.1 6.3 Smart grid and AMI costs B Undetermined 7.3 7.3 Unamortized loss on reacquired debt B Various 7.0 8.0 Deferred storm costs A Undetermined 2.1 — Total regulatory assets, non-current 163.2 203.9 Total regulatory assets $ 187.1 $ 204.0 Regulatory liabilities, current: Overcollection of costs to be refunded through rate riders A/B 2018 $ 14.8 $ 33.7 Total regulatory liabilities, current 14.8 33.7 Regulatory liabilities, non-current: Estimated costs of removal - regulated property Not Applicable 132.8 126.5 Deferred income taxes payable through rates Various 83.4 — Postretirement benefits B Ongoing 5.0 3.9 Total regulatory liabilities, non-current 221.2 130.4 Total regulatory liabilities $ 236.0 $ 164.1 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 recovery 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: Type of Recovery Amortization Through December 31, $ in millions 2017 2016 Regulatory assets, current: Undercollections to be collected through rate riders A/B 2018 $ 23.9 $ 0.1 Total regulatory assets, current 23.9 0.1 Regulatory assets, non-current: Pension benefits B Ongoing 92.4 97.6 Deferred recoverable income taxes B/C Ongoing — 35.9 Unrecovered OVEC charges D Undetermined 27.8 21.0 Fuel costs B 2020 9.3 15.4 Regulatory compliance costs B 2020 9.2 12.4 Rate case costs B Undetermined 8.1 6.3 Smart grid and AMI costs B Undetermined 7.3 7.3 Unamortized loss on reacquired debt B Various 7.0 8.0 Deferred storm costs A Undetermined 2.1 — Total regulatory assets, non-current 163.2 203.9 Total regulatory assets $ 187.1 $ 204.0 Regulatory liabilities, current: Overcollection of costs to be refunded through rate riders A/B 2018 $ 14.8 $ 33.7 Total regulatory liabilities, current 14.8 33.7 Regulatory liabilities, non-current: Estimated costs of removal - regulated property Not Applicable 132.8 126.5 Deferred income taxes payable through rates Various 83.4 — Postretirement benefits B Ongoing 5.0 3.9 Total regulatory liabilities, non-current 221.2 130.4 Total regulatory liabilities $ 236.0 $ 164.1 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 recovery is probable of occurring in future rate proceedings. |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
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, 2017 and 2016 : December 31, 2017 December 31, 2016 $ in millions Composite Rate Composite Rate Regulated: Transmission $ 242.7 4.0% $ 247.3 3.9% Distribution 1,197.5 4.9% 1,141.1 4.7% General 13.7 7.1% 13.7 7.4% Non-depreciable 64.7 N/A 63.5 N/A Total regulated 1,518.6 1,465.6 Unregulated: Production / Generation 10.9 63.2% 483.2 11.7% Other 19.4 7.0% 17.0 8.0% Non-depreciable 5.8 N/A 19.8 N/A Total unregulated 36.1 520.0 Total property, plant and equipment in service $ 1,554.7 5.0% $ 1,985.6 6.1% |
Ownership Interests | DPL’s undivided ownership interest in such facilities at December 31, 2017 , is as follows: DPL 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 $ 0.7 $ 0.7 $ 1.9 Killen - Unit 2 67.0 402 9.6 8.2 — Stuart - Units 2 through 4 35.0 606 1.8 1.8 — Transmission (at varying percentages) 45.6 13.3 — Total 1,137 $ 57.7 $ 24.0 $ 1.9 |
Changes in the Liability for Generation AROs | Changes in the Liability for Generation AROs $ in millions Balance at December 31, 2015 $ 65.9 Calendar 2016 Additions 70.2 Accretion expense 2.7 Settlements — Balance at December 31, 2016 138.8 Calendar 2017 Additions 0.1 Revisions to cash flow and timing estimates (6.3 ) Accretion expense 3.7 Settlements (0.1 ) Reductions due to plants sold or held-for-sale (5.0 ) Balance at December 31, 2017 $ 131.2 |
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, 2015 $ 121.8 Calendar 2016 Additions 11.7 Settlements (7.0 ) Balance at December 31, 2016 126.5 Calendar 2017 Additions 12.0 Settlements (5.7 ) Balance at December 31, 2017 $ 132.8 |
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, 2017 and 2016 : December 31, 2017 December 31, 2016 $ in millions Composite Rate Composite Rate Regulated: Transmission $ 414.6 2.4% $ 421.1 2.3% Distribution 1,735.9 3.4% 1,693.5 3.2% General 31.2 3.1% 31.6 3.2% Non-depreciable 64.6 N/A 63.5 N/A Total regulated 2,246.3 2,209.7 Unregulated: Other 0.2 2.7% 0.3 2.7% Non-depreciable 0.7 N/A 3.5 N/A Total unregulated 0.9 3.8 Total property, plant and equipment in service $ 2,247.2 3.4% $ 2,213.5 4.6% |
Changes in the Liability for Generation AROs | Changes in the Liability for Generation AROs $ in millions Balance at December 31, 2015 $ 5.0 Calendar 2016 Additions 2.7 Accretion expense 0.3 Settlements 0.2 Balance at December 31, 2016 8.2 Calendar 2017 Accretion expense 0.1 Settlements (0.3 ) Balance at December 31, 2017 $ 8.0 |
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, 2015 $ 121.8 Calendar 2016 Additions 11.7 Settlements (7.0 ) Balance at December 31, 2016 126.5 Calendar 2017 Additions 12.0 Settlements (5.7 ) Balance at December 31, 2017 $ 132.8 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
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, 2017 and 2016 . See Note 6 – Derivative Instruments and Hedging Activities for the fair values of our derivative instruments. December 31, 2017 December 31, 2016 $ in millions Cost Fair Value Cost Fair Value Assets Money market funds $ 0.3 $ 0.3 $ 0.4 $ 0.4 Equity securities 2.5 4.2 2.4 3.4 Debt securities 4.3 4.3 4.4 4.4 Hedge funds 0.1 0.2 — 0.1 Real estate — — 0.3 0.3 Tangible assets 0.1 0.1 0.1 0.1 Total assets $ 7.3 $ 9.1 $ 7.6 $ 8.7 Carrying Value Fair Value Carrying Value Fair Value Liabilities Long-term debt (a) $ 1,704.8 $ 1,819.3 $ 1,858.4 $ 1,907.7 |
Fair Value of Assets and Liabilities Measured on Recurring Basis | The fair value of assets and liabilities at December 31, 2017 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, 2017 (a) Based on Other Unobservable inputs Assets Master trust assets Money market funds $ 0.3 $ 0.3 $ — $ — Equity securities 4.2 — 4.2 — Debt securities 4.3 — 4.3 — Hedge funds 0.2 — 0.2 — Real estate — — — — Tangible assets 0.1 — 0.1 — Total Master trust assets 9.1 0.3 8.8 — Derivative assets Forward power contracts 10.8 — 10.8 — Interest rate hedge 1.8 — 1.8 — Natural gas 0.2 0.2 — — Total Derivative assets 12.8 0.2 12.6 — Total assets $ 21.9 $ 0.5 $ 21.4 $ — Liabilities FTRs $ 0.3 $ — $ — $ 0.3 Natural gas 0.1 0.1 — — Forward power contracts 14.9 — 14.9 — Total derivative liabilities 15.3 0.1 14.9 0.3 Long-term debt (b) 1,819.3 — 1,801.5 17.8 Total liabilities $ 1,834.6 $ 0.1 $ 1,816.4 $ 18.1 (a) Includes credit valuation adjustment (b) Amounts exclude immaterial capital lease obligations 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 Other 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 hedges 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 Interest rate hedges $ 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 (b) 1,907.7 — 1,889.7 18.0 Fair value per table above $ 1,907.7 Total liabilities $ 1,936.9 $ — $ 1,916.4 $ 20.5 (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 (c) Level 1 Level 2 Level 3 Loss Long-lived assets (a) Year ended December 31, 2017 AES Ohio Generation peakers December 31, 2017 $ 346.9 $ — $ — $ 237.5 $ 109.4 Stuart March 31, 2017 $ 42.4 $ — $ — $ 3.3 $ 39.1 Killen March 31, 2017 $ 35.2 $ — $ — $ 7.9 27.3 $ 175.8 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 $ 859.0 Goodwill (b) Year ended December 31, 2015 DP&L reporting unit December 31, 2015 $ 317.0 $ — $ — $ — $ 317.0 (a) See Note 15 – Fixed-asset Impairments for further information (b) See Note 7 – Goodwill for further information (c) Carrying amount at date of valuation |
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, 2017 and 2016 . See also Note 6 – Derivative Instruments and Hedging Activities for the fair values of our derivative instruments. December 31, 2017 December 31, 2016 $ in millions Cost Fair Value Cost Fair Value Assets Money market funds $ 0.3 $ 0.3 $ 0.4 $ 0.4 Equity securities 2.5 4.2 2.4 3.4 Debt securities 4.3 4.3 4.4 4.4 Hedge funds 0.1 0.2 — 0.1 Real estate — — 0.3 0.3 Tangible assets 0.1 0.1 0.1 0.1 Total assets $ 7.3 $ 9.1 $ 7.6 $ 8.7 Carrying Value Fair Value Carrying Value Fair Value Liabilities Long-term debt (a) $ 646.6 $ 658.4 $ 735.7 $ 750.1 |
Fair Value of Assets and Liabilities Measured on Recurring Basis | The fair value of assets and liabilities at December 31, 2017 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, 2017 (a) Based on Other Unobservable inputs Assets Master trust assets Money market funds $ 0.3 $ 0.3 $ — $ — Equity securities 4.2 — 4.2 — Debt securities 4.3 — 4.3 — Hedge funds 0.2 — 0.2 — Real estate — — — — Tangible assets 0.1 — 0.1 — Total Master trust assets 9.1 0.3 8.8 — Derivative assets Interest rate hedges 1.8 — 1.8 — Total derivative assets 1.8 — 1.8 — Total assets $ 10.9 $ 0.3 $ 10.6 $ — Liabilities Long-term debt $ 658.4 $ — $ 640.6 $ 17.8 Total liabilities $ 658.4 $ — $ 640.6 $ 17.8 (a) Includes credit valuation adjustment (b) Amounts exclude immaterial capital lease obligations 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 Other 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 assets $ 8.7 $ 0.4 $ 8.3 $ — Liabilities Long-term debt (b) $ 750.1 $ — $ 732.1 $ 18.0 Total liabilities $ 750.1 $ — $ 732.1 $ 18.0 (a) Includes credit valuation adjustment (b) Amounts exclude immaterial capital lease obligations |
Derivative Instruments and He36
Derivative Instruments and Hedging Activities (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Schedule of Notional Amounts of Outstanding Derivative Positions | At December 31, 2017 , DPL's outstanding derivative instruments were as follows: Commodity Accounting Treatment (a) Unit Purchases Sales Net Purchases/ (Sales) FTRs Not designated MWh 2.1 — 2.1 Natural Gas Not designated Dths 3,322.5 (390.0 ) 2,932.5 Forward Power Contracts Designated MWh 678.5 (1,667.0 ) (988.5 ) Forward Power Contracts Not designated MWh 871.0 (765.6 ) 105.4 Interest Rate Swaps Designated USD $ 200,000.0 $ — $ 200,000.0 (a) Refers to whether the derivative instruments have been designated as a cash flow hedge. At December 31, 2016 , DPL's outstanding derivative instruments were as follows: Commodity Accounting Treatment (a) Unit Purchases Sales Net Purchases/ (Sales) 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 (a) Refers to whether the derivative instruments have been designated as a cash flow hedge. |
Gains or Losses Recognized in AOCI for the Cash Flow Hedges | The following tables provide information on gains or losses recognized in AOCI for the cash flow hedges for the periods indicated: Years ended December 31, 2017 2016 2015 $ in millions (net of tax) Power Interest Rate Power Interest Rate Power Interest Rate Beginning accumulated derivative gain / (loss) in AOCI $ (4.3 ) $ 17.4 $ 9.2 $ 17.5 $ 0.2 $ 18.3 Net gains / (losses) associated with current period hedging transactions 8.8 0.8 15.7 0.4 18.2 — Net gains / (losses) reclassified to earnings: Interest Expense — (0.7 ) — (0.5 ) — (0.8 ) Revenues (9.8 ) — (35.6 ) — (12.0 ) — Purchased Power 2.5 — 6.4 — 2.8 — Ending accumulated derivative gain / (loss) in AOCI $ (2.8 ) $ 17.5 $ (4.3 ) $ 17.4 $ 9.2 $ 17.5 Portion expected to be reclassified to earnings in the next twelve months (a) $ (2.7 ) $ (0.7 ) Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) 3 32 (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, 2017 , 2016 and 2015 : Year ended December 31, 2017 $ in millions FTRs Power Natural Gas Total Change in unrealized gain / (loss) $ (0.4 ) $ 1.9 $ 0.1 $ 1.6 Realized gain / (loss) 0.8 (0.7 ) 1.5 1.6 Total $ 0.4 $ 1.2 $ 1.6 $ 3.2 Recorded on Balance Sheet: Regulatory asset $ — $ — $ — $ — Recorded in Statement of Operations: gain / (loss) Revenue — (1.2 ) — (1.2 ) Purchased Power 0.4 2.4 1.6 4.4 Total $ 0.4 $ 1.2 $ 1.6 $ 3.2 Year ended December 31, 2016 $ in millions FTRs Power Natural Gas Total 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 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) Fuel — — 27.4 — 27.4 Purchased Power — 0.1 (43.6 ) — (43.5 ) Total $ 0.1 $ 0.1 $ (16.2 ) $ — $ (16.0 ) |
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block] | The following tables summarize the derivative positions presented in the balance sheet where a right of offset exists under these arrangements and related cash collateral received or pledged; as well as the fair value, balance sheet classification and hedging designation of DPL’s derivative instruments. Fair Values of Derivative Instruments December 31, 2017 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 $ 4.9 $ (4.9 ) $ — $ — Forward power contracts Not designated 5.3 (3.7 ) — 1.6 Natural gas Not designated 0.2 (0.1 ) — 0.1 Long-term derivative positions (presented in Other deferred assets) Interest Rate Swaps Designated 1.8 — — 1.8 Forward power contracts Designated — — — — Forward power contracts Not designated 0.6 — — 0.6 Total assets $ 12.8 $ (8.7 ) $ — $ 4.1 Liabilities Short-term derivative positions (presented in Other current liabilities) Forward power contracts Designated $ 9.0 $ (4.9 ) $ (1.4 ) $ 2.7 Forward power contracts Not designated 5.9 (3.7 ) — 2.2 Natural gas Not designated 0.1 (0.1 ) — — FTRs Not designated 0.3 — — 0.3 Total liabilities $ 15.3 $ (8.7 ) $ (1.4 ) $ 5.2 (a) Includes credit valuation adjustment. 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 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. |
Schedule of Interest Rate Derivatives [Table Text Block] | The fair value derivative position of DP&L's interest rate swaps are as follows: December 31, Hedging Designation Balance sheet classification 2017 2016 Interest Rate Hedges in an Asset Position Cash Flow Hedge Other Deferred Assets Gross Fair Value as presented in the Balance Sheets $ 1.8 $ 1.2 Interest Rate Hedges in a Liability Position Cash Flow Hedge Other Current Liabilities Gross Fair Value as presented in the Balance Sheets $ — $ 0.7 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Gains or Losses Recognized in AOCI for the Cash Flow Hedges | The following tables provide information on gains or losses recognized in AOCI for the cash flow hedges for the periods indicated: Years ended December 31, 2017 2016 2015 $ in millions (net of tax) Power Interest Rate Power Interest Rate Power Interest Rate Beginning accumulated derivative gain / (loss) in AOCI $ (4.3 ) $ 1.6 $ 9.2 $ 2.0 $ 0.2 $ 2.6 Net gains / (losses) associated with current period hedging transactions 10.7 1.7 15.7 0.4 18.2 — Net gains / (losses) reclassified to earnings: Interest expense — (0.7 ) — (0.8 ) — (0.6 ) Loss from discontinued operations (5.5 ) — (29.2 ) — (9.2 ) — Transfer of generation assets to subsidiary of parent $ (2.1 ) $ — $ — $ — $ — $ — Ending accumulated derivative gain / (loss) in AOCI $ (1.2 ) $ 2.6 $ (4.3 ) $ 1.6 $ 9.2 $ 2.0 Portion expected to be reclassified to earnings in the next twelve months $ (0.7 ) Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) 32 |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Debt Instrument [Line Items] | |
Long-term Debt | Long-term debt $ in millions Interest Rate Maturity December 31, 2017 December 31, 2016 Term loan - rates from: 4.01% - 4.60% (a) and 4.00% - 4.01% (b) 2022 $ 440.6 $ 445.0 Tax-exempt First Mortgage Bonds 4.8% 2036 — 100.0 Tax-exempt First Mortgage Bonds - rates from: 1.52% - 1.92% (a) and 1.29% - 1.42% (b) 2020 200.0 200.0 U.S. Government note 4.2% 2061 17.8 18.0 Capital leases 0.2 0.4 Unamortized deferred financing costs (9.8 ) (10.7 ) Unamortized debt discounts and premiums, net (2.0 ) (5.5 ) Total long-term debt at subsidiary 646.8 747.2 Bank term loan - rates from: 3.02% - 4.10% (a) and 2.67% - 3.02% (b) 2020 70.0 125.0 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 (6.8 ) (8.8 ) Unamortized debt discounts and premiums, net (0.5 ) (0.6 ) Total long-term debt 1,705.1 1,858.4 Less: current portion (4.7 ) (29.7 ) Long-term debt, net of current portion $ 1,700.4 $ 1,828.7 (a) Range of interest rates for the year ended December 31, 2017 . (b) Range of interest rates for the year ended December 31, 2016 . (c) Note payable to related party. See Note 13 – Related Party Transactions for additional information. |
Long-term Debt Maturities | At December 31, 2017 , maturities of long-term debt are summarized as follows: Due during the years ending December 31, $ in millions 2018 $ 4.7 2019 224.5 2020 254.6 2021 784.6 2022 422.9 Thereafter 32.7 1,724.0 Unamortized discounts and premiums, net (2.5 ) Total long-term debt $ 1,721.5 |
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, 2017 December 31, 2016 Term loan - rates from: 4.01% - 4.60% (a) and 4.00% - 4.01% (b) 2022 $ 440.6 $ 445.0 Tax-exempt First Mortgage Bonds 4.8% 2036 — 100.0 Tax-exempt First Mortgage Bonds - rates from: 1.52% - 1.92% (a) and 1.29% - 1.42% (b) 2020 200.0 200.0 U.S. Government note 4.2% 2061 17.8 18.0 Capital leases — 0.4 Debt classified as held-for-sale — (13.4 ) Unamortized deferred financing costs (9.8 ) (11.7 ) Unamortized debt discount (2.0 ) (2.2 ) Total long-term debt 646.6 736.1 Less: current portion (4.6 ) (4.6 ) Long-term debt, net of current portion $ 642.0 $ 731.5 (a) Range of interest rates for the year ended December 31, 2017 . (b) Range of interest rates for the year ended December 31, 2016 |
Long-term Debt Maturities | At December 31, 2017 , maturities of long-term debt are summarized as follows: Due during the years ending December 31, $ in millions 2018 $ 4.6 2019 4.6 2020 204.6 2021 4.6 2022 422.9 Thereafter 17.1 658.4 Unamortized discounts and premiums, net (2.0 ) Total long-term debt $ 656.4 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
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 2017 2016 2015 Computation of tax expense / (benefit) Federal income tax benefit (a) $ (42.0 ) $ (277.6 ) $ (81.0 ) Increases (decreases) in tax resulting from: State income taxes, net of federal effect (0.5 ) (1.0 ) (0.1 ) Depreciation of AFUDC - Equity 0.8 2.7 (3.5 ) Investment tax credit amortized (0.3 ) (0.4 ) (0.5 ) Section 199 - domestic production deduction — (4.5 ) (4.1 ) Non-deductible goodwill impairment — — 111.0 Accrual (settlement) for open tax years (0.4 ) 2.2 — Other, net (b) 17.1 (0.2 ) (1.8 ) Tax expense / (benefit) $ (25.3 ) $ (278.8 ) $ 20.0 Components of tax expense / (benefit) Federal - current $ (2.9 ) $ 14.7 $ 30.1 State and Local - current — 0.6 0.8 Total current (2.9 ) 15.3 30.9 Federal - deferred (22.0 ) (290.2 ) (9.9 ) State and local - deferred (0.4 ) (3.9 ) (1.0 ) Total deferred (22.4 ) (294.1 ) (10.9 ) Tax expense / (benefit) $ (25.3 ) $ (278.8 ) $ 20.0 (a) The statutory tax rate of 35% was applied to pre-tax earnings. (b) Includes expense / (benefit) of $3.5 million , $(0.3) million and $0.2 million in the years ended December 31, 2017 , 2016 , and 2015 , respectively, of income tax related to adjustments from prior years. The 2017 tax year also includes a one-time remeasurement of deferred tax expense related to the recent enactment of the TCJA of $13.7 million . |
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, 2017 , 2016 and 2015 : Years ended December 31, 2017 2016 2015 Statutory Federal tax rate 35.0 % 35.0 % 35.0 % State taxes, net of Federal tax benefit 0.4 % 0.1 % 0.1 % AFUDC - Equity (0.7 )% (0.3 )% 1.5 % Amortization of investment tax credits 0.3 % — % 0.2 % Section 199 - domestic production deduction — % 0.6 % 1.8 % Non-deductible goodwill impairment — % — % (48.0 )% Other, net (a) (13.9 )% (0.3 )% 0.8 % Effective tax rate 21.1 % 35.1 % (8.6 )% (a) In 2017, this is primarily a result of the application of the TCJA. |
Components of Deferred Tax Assets and Liabilities | Components of Deferred Tax Assets and Liabilities December 31, $ in millions 2017 2016 Net non-current assets / (liabilities) Depreciation / property basis $ (103.6 ) $ (234.8 ) Income taxes recoverable / (payable) 11.0 (11.9 ) Regulatory assets (23.1 ) (7.8 ) Investment tax credit 0.5 0.5 Compensation and employee benefits 11.3 5.5 Intangibles (0.4 ) (1.5 ) Long-term debt (0.2 ) (0.7 ) Other (a) (6.7 ) (1.7 ) Net non-current liabilities $ (111.2 ) $ (252.4 ) (a) The Other caption includes deferred tax assets of $36.3 million in 2017 and $38.3 million in 2016 related to state and local tax net operating loss carryforwards, net of related valuation allowances of $36.3 million in 2017 and $38.3 million in 2016 . These net operating loss carryforwards expire from 2018 to 2037. |
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 2017 2016 2015 Tax expense / (benefit) $ 0.2 $ (9.6 ) $ 6.3 |
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, 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 Calendar 2017 Tax positions taken during prior period — Lapse of Statute of Limitations (0.2 ) Balance at December 31, 2017 $ 3.5 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Income Taxes [Line Items] | |
Components of Income Tax Expense | DP&L’s components of income tax expense on continuing operations were as follows: Years ended December 31, $ in millions 2017 2016 2015 Computation of tax expense Federal income tax expense (a) $ 31.0 $ 50.1 $ 65.8 Increases (decreases) in tax resulting from: State income taxes, net of federal effect 0.4 0.4 0.4 Depreciation of AFUDC - Equity 1.2 3.0 (3.1 ) Investment tax credit amortized (0.3 ) (0.4 ) (0.4 ) Accrual (settlement) for open tax years (0.5 ) 3.4 — Other, net (b) (0.7 ) (10.5 ) (3.7 ) Total tax expense $ 31.1 $ 46.0 $ 59.0 Components of tax expense Federal - current $ 13.5 $ 37.7 $ 68.3 State and Local - current 0.2 0.5 0.9 Total current 13.7 38.2 69.2 Federal - deferred 17.0 7.7 (9.9 ) State and local - deferred 0.4 0.1 (0.3 ) Total deferred 17.4 7.8 (10.2 ) Total tax expense $ 31.1 $ 46.0 $ 59.0 (a) The statutory tax rate of 35% was applied to pre-tax earnings. (b) Includes expense / (benefit) of $0.0 million , $(0.4) million and $0.1 million in the years ended December 31, 2017 , 2016 and 2015 , 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, 2017 , 2016 and 2015 : Years ended December 31, 2017 2016 2015 Statutory Federal tax rate 35.0 % 35.0 % 35.0 % State taxes, net of Federal tax benefit 0.4 % 0.3 % 0.2 % AFUDC - Equity 1.4 % 2.1 % (1.7 )% Amortization of investment tax credits (0.4 )% (0.3 )% (0.2 )% Other - net (1.3 )% (5.1 )% (2.1 )% Effective tax rate 35.1 % 32.0 % 31.2 % |
Components of Deferred Tax Assets and Liabilities | Components of Deferred Tax Assets and Liabilities December 31, $ in millions 2017 2016 Net non-current assets / (liabilities) Depreciation / property basis $ (126.5 ) $ (238.0 ) Income taxes recoverable / (payable) 11.0 (12.2 ) Regulatory assets (23.9 ) (9.1 ) Investment tax credit 0.4 0.4 Compensation and employee benefits 17.6 (0.3 ) Other (9.6 ) (7.7 ) Net non-current liabilities $ (131.0 ) $ (266.9 ) |
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 2017 2016 2015 Tax expense / (benefit) $ 4.0 $ (7.0 ) $ 7.5 |
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, 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 Calendar 2017 Tax positions taken during prior period — Lapse of Statute of Limitations (0.1 ) Balance at December 31, 2017 $ 4.8 |
Benefit Plans (Tables)
Benefit Plans (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
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 Consolidated Balance Sheets at December 31, 2017 and 2016 . 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 $1.1 million and $1.3 million of costs billed to the service company for the years ended December 31, 2017 and 2016 . $ in millions Years ended December 31, Change in benefit obligation 2017 2016 Benefit obligation at January 1 $ 419.6 $ 410.8 Service cost 5.7 5.7 Interest cost 14.2 14.7 Plan curtailment 3.0 2.5 Actuarial loss 28.1 9.0 Benefits paid (33.7 ) (23.1 ) Benefit obligation at December 31 436.9 419.6 Change in plan assets Fair value of plan assets at January 1 341.0 345.4 Actual return on plan assets 44.8 13.3 Employer contributions 5.4 5.4 Benefits paid (33.7 ) (23.1 ) Fair value of plan assets at December 31 357.5 341.0 Unfunded status of plan $ (79.4 ) $ (78.6 ) December 31, Amounts recognized in the Balance sheets 2017 2016 Current liabilities $ (0.4 ) $ (0.4 ) Non-current liabilities (79.0 ) (78.2 ) Net liability at end of year $ (79.4 ) $ (78.6 ) Amounts recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax Components: Prior service cost $ 4.9 $ 8.8 Net actuarial loss 111.4 108.9 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 116.3 $ 117.7 Recorded as: Regulatory asset $ 92.1 $ 97.1 Accumulated other comprehensive income 24.2 20.6 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 116.3 $ 117.7 |
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 Consolidated Balance Sheets at December 31, 2017 and 2016 . 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 $1.1 million and $1.3 million of costs billed to the service company for the years ended December 31, 2017 and 2016 . $ in millions Years ended December 31, Change in benefit obligation 2017 2016 Benefit obligation at January 1 $ 419.6 $ 410.8 Service cost 5.7 5.7 Interest cost 14.2 14.7 Plan curtailment 3.0 2.5 Actuarial loss 28.1 9.0 Benefits paid (33.7 ) (23.1 ) Benefit obligation at December 31 436.9 419.6 Change in plan assets Fair value of plan assets at January 1 341.0 345.4 Actual return on plan assets 44.8 13.3 Employer contributions 5.4 5.4 Benefits paid (33.7 ) (23.1 ) Fair value of plan assets at December 31 357.5 341.0 Unfunded status of plan $ (79.4 ) $ (78.6 ) December 31, Amounts recognized in the Balance sheets 2017 2016 Current liabilities $ (0.4 ) $ (0.4 ) Non-current liabilities (79.0 ) (78.2 ) Net liability at end of year $ (79.4 ) $ (78.6 ) Amounts recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax Components: Prior service cost $ 4.9 $ 8.8 Net actuarial loss 111.4 108.9 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 116.3 $ 117.7 Recorded as: Regulatory asset $ 92.1 $ 97.1 Accumulated other comprehensive income 24.2 20.6 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 116.3 $ 117.7 |
Schedule of Net Periodic Benefit Cost / (Income) | The net periodic benefit cost of the pension plans was: Years ended December 31, $ in millions 2017 2016 2015 Service cost $ 5.7 $ 5.7 $ 7.1 Interest cost 14.2 14.7 17.3 Expected return on assets (22.8 ) (22.8 ) (22.6 ) Plan curtailment 4.1 3.8 — Amortization of unrecognized: Actuarial loss 5.3 4.3 5.8 Prior service cost 1.1 1.8 2.0 Net periodic benefit cost $ 7.6 $ 7.5 $ 9.6 Rates relevant to each year's expense calculations Discount rate 4.28 % 4.49 % 4.02 % Expected return on plan assets 6.50 % 6.50 % 6.50 % |
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 2017 2016 2015 Net actuarial loss / (gain) $ 9.1 $ 20.9 $ (3.0 ) Prior service cost — — — Plan curtailment (4.1 ) (3.8 ) — Reversal of amortization item: Net actuarial loss (5.3 ) (4.3 ) (5.8 ) Prior service cost (1.1 ) (1.8 ) (2.0 ) Total recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities $ (1.4 ) $ 11.0 $ (10.8 ) Total recognized in net periodic benefit cost and Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities $ 6.2 $ 18.5 $ (1.2 ) |
Weighted Average Assumptions Used to Determine Benefit Obligations | The weighted average assumptions used to determine benefit obligations at December 31, 2017 , 2016 and 2015 were: Benefit Obligation Assumptions Pension 2017 2016 2015 Discount rate for obligations 3.66% 4.28% 4.49% 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 2017 : Long-Term Percentage of plan assets as of December 31, Asset category 2017 2016 Equity Securities 38% 35% 37% Debt Securities 56% 55% 53% Real Estate 6% 10% 10% |
Estimated Future Benefit Payments and Medicare Part D Reimbursements | 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 2018 $ 28.4 2019 $ 28.2 2020 $ 27.9 2021 $ 27.6 2022 $ 27.3 2023 - 2027 $ 131.3 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Schedule of Amounts Recognized in Balance Sheet | December 31, 2017 and 2016 . 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 $1.1 million and $1.3 million of costs billed to the service company for the years ended December 31, 2017 and 2016 or $0.7 million of costs billed to AES Ohio Generation for the year ended December 31, 2017. $ in millions Years ended December 31, Change in benefit obligation 2017 2016 Benefit obligation at January 1 $ 419.6 $ 410.8 Service cost 5.7 5.7 Interest cost 14.2 14.7 Plan curtailment 3.0 2.5 Actuarial loss 28.1 9.0 Benefits paid (33.7 ) (23.1 ) Benefit obligation at December 31 436.9 419.6 Change in plan assets Fair value of plan assets at January 1 341.0 345.4 Actual return on plan assets 44.8 13.3 Employer contributions 5.4 5.4 Benefits paid (33.7 ) (23.1 ) Fair value of plan assets at December 31 357.5 341.0 Unfunded status of plan $ (79.4 ) $ (78.6 ) December 31, Amounts recognized in the Balance sheets 2017 2016 Current liabilities $ (0.4 ) $ (0.4 ) Non-current liabilities (79.0 ) (78.2 ) Net liability at end of year $ (79.4 ) $ (78.6 ) Amounts recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax Components: Prior service cost $ 6.7 $ 8.8 Net actuarial loss 148.3 108.9 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 155.0 $ 117.7 Recorded as: Regulatory asset $ 92.2 $ 97.1 Accumulated other comprehensive income 62.8 20.6 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 155.0 $ 117.7 |
Schedule of Net Periodic Benefit Cost / (Income) | The net periodic benefit cost of the pension plans was: Years ended December 31, $ in millions 2017 2016 2015 Service cost $ 5.7 $ 5.7 $ 7.1 Interest cost 14.2 14.7 17.3 Expected return on assets (22.8 ) (22.8 ) (22.6 ) Plan curtailment 5.6 5.7 — Amortization of unrecognized: Actuarial loss 8.7 7.2 9.8 Prior service cost 1.5 3.0 3.3 Net periodic benefit cost $ 12.9 $ 13.5 $ 14.9 Rates relevant to each year's expense calculations Discount rate 4.28 % 4.49 % 4.02 % Expected return on plan assets 6.50 % 6.50 % 6.50 % |
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 2018 are: $ in millions Pension Actuarial loss $ 9.4 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, 2017 , 2016 and 2015 were: Benefit Obligation Assumptions Pension 2017 2016 2015 Discount rate for obligations 3.66% 4.28% 4.49% 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 2017 : Long-Term Percentage of plan assets as of December 31, Asset category 2017 2016 Equity Securities 38% 35% 37% Debt Securities 56% 55% 53% Real Estate 6% 10% 10% |
Fair Value Measurements for Plan Assets | The fair values of our pension plan assets at December 31, 2017 by asset category are as follows: Fair Value Measurements for Pension Plan Assets at December 31, 2017 $ in millions Market Value at December 31, 2017 Quoted prices Significant Significant Asset category (Level 1) (Level 2) (Level 3) Mutual funds: U.S. equities (a) $ 78.2 $ 78.2 $ — $ — International equities (a) 46.3 46.3 — — Fixed income (b) 163.3 163.3 — — Fixed income securities: U.S. Treasury securities 33.5 33.5 — — Other investments: Core property collective fund (c) 36.2 — 36.2 — Total pension plan assets $ 357.5 $ 321.3 $ 36.2 $ — (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, 2016 by asset category are as follows: Fair Value Measurements for Pension Plan Assets at December 31, 2016 $ in millions Market Value at December 31, 2016 Quoted prices Significant Significant Asset category (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: (c) Core property collective fund 33.1 — 33.1 — Common collective fund — — — — 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. |
Estimated Future Benefit Payments and Medicare Part D Reimbursements | Estimated future benefit payments $ in millions due within the following years: Pension 2018 $ 28.4 2019 $ 28.2 2020 $ 27.9 2021 $ 27.6 2022 $ 27.3 2023 - 2027 $ 131.3 |
Pension [Member] | |
Fair Value Measurements for Plan Assets | The fair values of our pension plan assets at December 31, 2017 by asset category are as follows: Fair Value Measurements for Pension Plan Assets at December 31, 2017 $ in millions Market Value at December 31, 2017 Quoted prices Significant Significant Asset category (Level 1) (Level 2) (Level 3) Mutual funds: U.S. equities (a) $ 78.2 $ 78.2 $ — $ — International equities (a) 46.3 46.3 — — Fixed income (b) 163.3 163.3 — — Fixed income securities: U.S. Treasury securities 33.5 33.5 — — Other investments: Core property collective fund (c) 36.2 — 36.2 — Total pension plan assets $ 357.5 $ 321.3 $ 36.2 $ — (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, 2016 by asset category are as follows: Fair Value Measurements for Pension Plan Assets at December 31, 2016 $ in millions Market Value at December 31, 2016 Quoted prices Significant Significant Asset category (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: (c) Core property collective fund 33.1 — 33.1 — Common collective fund — — — — 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. |
Pension [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Pension And Postretirement Benefit Plans' Obligations And Assets | $ in millions Years ended December 31, Change in benefit obligation 2017 2016 Benefit obligation at January 1 $ 419.6 $ 410.8 Service cost 5.7 5.7 Interest cost 14.2 14.7 Plan curtailment 3.0 2.5 Actuarial loss 28.1 9.0 Benefits paid (33.7 ) (23.1 ) Benefit obligation at December 31 436.9 419.6 Change in plan assets Fair value of plan assets at January 1 341.0 345.4 Actual return on plan assets 44.8 13.3 Employer contributions 5.4 5.4 Benefits paid (33.7 ) (23.1 ) Fair value of plan assets at December 31 357.5 341.0 Unfunded status of plan $ (79.4 ) $ (78.6 ) December 31, Amounts recognized in the Balance sheets 2017 2016 Current liabilities $ (0.4 ) $ (0.4 ) Non-current liabilities (79.0 ) (78.2 ) Net liability at end of year $ (79.4 ) $ (78.6 ) Amounts recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax Components: Prior service cost $ 6.7 $ 8.8 Net actuarial loss 148.3 108.9 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 155.0 $ 117.7 Recorded as: Regulatory asset $ 92.2 $ 97.1 Accumulated other comprehensive income 62.8 20.6 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 155.0 $ 117.7 |
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 2017 2016 2015 Net actuarial loss / (gain) $ 9.1 $ 20.9 $ (3.0 ) Prior service cost — — — Plan curtailment (5.6 ) (5.7 ) — Reversal of amortization item: Net actuarial loss (8.7 ) (7.2 ) (9.8 ) Prior service cost (1.5 ) (3.0 ) (3.3 ) Total recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities $ (6.7 ) $ 5.0 $ (16.1 ) Total recognized in net periodic benefit cost and Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities $ 6.2 $ 18.5 $ (1.2 ) |
Scenario, Forecast [Member] | |
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 2018 are: $ in millions Pension Actuarial loss $ 6.4 Prior service cost $ 0.9 |
Contractual Obligations, Comm40
Contractual Obligations, Commercial Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
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, 2017 , these include: Payments due in: $ in millions Total Less than 2 - 3 4 - 5 More than Electricity purchase commitments $ 370.9 $ 178.5 $ 171.2 $ 21.2 $ — Coal and limestone contracts (a) $ 54.9 $ 54.9 $ — $ — $ — Purchase orders and other contractual obligations $ 73.0 $ 18.9 $ 27.1 $ 27.0 $ — (a) Total at DPL 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, 2017 , these include: Payments due in: $ in millions Total Less than 2 - 3 4 - 5 More than Electricity purchase commitments $ 370.9 $ 178.5 $ 171.2 $ 21.2 $ — Purchase orders and other contractual obligations $ 73.0 $ 18.9 $ 27.1 $ 27.0 $ — |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Entity Information [Line Items] | |
Schedule of Related Party Transactions | The following table provides a summary of these transactions: Years ended December 31, $ in millions 2017 2016 2015 Transactions with the Service Company Charges for services provided $ 46.5 $ 42.8 $ 36.0 Charges to the Service Company $ 4.2 $ 4.6 $ 6.2 Transactions with other AES affiliates: Payments for health, welfare and benefit plans $ 15.4 $ 9.6 $ 15.5 Balances with related parties: At December 31, 2017 At December 31, 2016 Net payable to the Service Company $ (3.9 ) $ (2.0 ) Net payable to other AES affiliates $ (0.6 ) $ (2.5 ) |
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 2017 2016 2015 DP&L revenues: Sales to DPLER (including MC Squared) (a) $ — $ — $ 303.3 DP&L Cost of revenues: Fuel and power purchased from AES Ohio Generation $ 5.4 $ 8.7 $ 5.2 DP&L Operation & Maintenance Expenses: Premiums charged for insurance services provided by MVIC (b) $ 3.1 $ 3.4 $ 3.2 Expense recoveries for services provided to DPLER (c) $ — $ — $ 2.4 Transactions with the Service Company: Charges for services provided $ 39.0 $ 38.7 $ 30.9 Charges to the Service Company $ 4.2 $ 4.5 $ 6.1 Transactions with other AES affiliates: Charges for health, welfare and benefit plans $ 14.3 $ 9.4 $ 14.8 Charges to affiliates for non-power goods or services (c) $ 3.7 $ 5.7 $ 4.9 Balances with related parties: At December 31, 2017 At December 31, 2016 Net payable to the Service Company $ (3.9 ) $ (2.0 ) Short-term loan with DPL $ — $ 5.0 Net receivable from / (payable) to other AES affiliates $ 4.8 $ (2.5 ) (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 charged by MVIC to DP&L . (c) In the normal course of business DP&L incurred and recorded expenses on behalf of DPL affiliates, which included 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 the affiliates 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, 2017 | |
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, 2017 Revenues from external customers $ 718.9 $ 507.9 $ 10.1 $ — $ 1,236.9 Intersegment revenues 1.1 — 4.4 (5.5 ) — Total revenues $ 720.0 $ 507.9 $ 14.5 $ (5.5 ) $ 1,236.9 Depreciation and amortization $ 75.3 $ 20.9 $ 10.7 $ — $ 106.9 Fixed-asset impairment (Note 15) $ — $ 66.3 $ 109.5 $ — $ 175.8 Interest expense $ 30.5 $ 0.1 $ 79.5 $ — $ 110.1 Income / (loss) from continuing operations before income tax $ 88.5 $ (18.5 ) $ (189.9 ) $ — $ (119.9 ) Cash capital expenditures $ 85.6 $ 31.3 $ 4.6 $ — $ 121.5 Total assets (end of year) $ 1,689.4 $ 275.0 $ 468.0 $ (383.2 ) $ 2,049.2 $ 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 $ 25.4 $ 0.4 $ 82.2 $ (0.3 ) $ 107.7 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 $ 29.8 $ 2.9 $ 87.4 $ (0.3 ) $ 119.8 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. |
Fixed Asset Impairment Fixed As
Fixed Asset Impairment Fixed Asset Impairment (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Property, Plant and Equipment [Line Items] | |
Schedule of Fixed Asset Impairments | During the years ended December 31, 2017 , 2016 and 2015 , DPL had the following fixed-asset impairments: Years ended December 31, $ in millions Measurement Date 2017 2016 2015 AES Ohio Generation peakers December 31, 2017 $ 109.4 $ — $ — Stuart March 31, 2017 39.1 — — Killen March 31, 2017 27.3 — — 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 — Total impairment loss $ 175.8 $ 859.0 $ — |
Discontinued Operations (Tables
Discontinued Operations (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Summary of Balance Sheet and Profit and Loss Information for Discontinued Operations | The following table summarizes the revenues, cost of revenues, operating expenses and income tax of discontinued operations for the periods indicated: Years ended December 31, $ in millions 2016 2015 Revenues $ — $ 340.9 Cost of revenues — (307.0 ) Operating expenses (0.7 ) (22.5 ) Income / (loss) from discontinued operations before income tax (0.7 ) 11.4 Gain from disposal of discontinued operations 49.2 — Income tax expense / (benefit) from discontinued operations 19.2 (1.0 ) Income from discontinued operations $ 29.3 $ 12.4 The following table summarizes the major classes of assets and liabilities classified as held-for-sale as of December 31, 2017: $ in millions December 31, 2017 Assets Accounts receivable, net $ 3.8 Inventories 7.6 Taxes applicable to subsequent years 4.9 Property, plant & equipment, net 233.7 Other assets 0.3 Total assets of the disposal group classified as held-for-sale in the balance sheet $ 250.3 Liabilities Accounts payable $ 3.9 Accrued taxes 3.6 Taxes payable 4.9 Asset retirement obligations 0.6 Other liabilities 0.2 Total liabilities of the disposal group classified as held-for-sale in the balance sheet $ 13.2 |
Assets and Liabilities Held-F45
Assets and Liabilities Held-For-Sale and Dispositions (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |
Summary of Balance Sheet and Profit and Loss Information for Discontinued Operations | The following table summarizes the revenues, cost of revenues, operating expenses and income tax of discontinued operations for the periods indicated: Years ended December 31, $ in millions 2016 2015 Revenues $ — $ 340.9 Cost of revenues — (307.0 ) Operating expenses (0.7 ) (22.5 ) Income / (loss) from discontinued operations before income tax (0.7 ) 11.4 Gain from disposal of discontinued operations 49.2 — Income tax expense / (benefit) from discontinued operations 19.2 (1.0 ) Income from discontinued operations $ 29.3 $ 12.4 The following table summarizes the major classes of assets and liabilities classified as held-for-sale as of December 31, 2017: $ in millions December 31, 2017 Assets Accounts receivable, net $ 3.8 Inventories 7.6 Taxes applicable to subsequent years 4.9 Property, plant & equipment, net 233.7 Other assets 0.3 Total assets of the disposal group classified as held-for-sale in the balance sheet $ 250.3 Liabilities Accounts payable $ 3.9 Accrued taxes 3.6 Taxes payable 4.9 Asset retirement obligations 0.6 Other liabilities 0.2 Total liabilities of the disposal group classified as held-for-sale in the balance sheet $ 13.2 |
Generation Separation (Tables)
Generation Separation (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |
Summary of Balance Sheet and Profit and Loss Information for Discontinued Operations | The following table summarizes the revenues, cost of revenues, operating expenses and income tax of discontinued operations for the periods indicated: Years ended December 31, $ in millions 2016 2015 Revenues $ — $ 340.9 Cost of revenues — (307.0 ) Operating expenses (0.7 ) (22.5 ) Income / (loss) from discontinued operations before income tax (0.7 ) 11.4 Gain from disposal of discontinued operations 49.2 — Income tax expense / (benefit) from discontinued operations 19.2 (1.0 ) Income from discontinued operations $ 29.3 $ 12.4 The following table summarizes the major classes of assets and liabilities classified as held-for-sale as of December 31, 2017: $ in millions December 31, 2017 Assets Accounts receivable, net $ 3.8 Inventories 7.6 Taxes applicable to subsequent years 4.9 Property, plant & equipment, net 233.7 Other assets 0.3 Total assets of the disposal group classified as held-for-sale in the balance sheet $ 250.3 Liabilities Accounts payable $ 3.9 Accrued taxes 3.6 Taxes payable 4.9 Asset retirement obligations 0.6 Other liabilities 0.2 Total liabilities of the disposal group classified as held-for-sale in the balance sheet $ 13.2 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |
Summary of Balance Sheet and Profit and Loss Information for Discontinued Operations | The following table summarizes the carrying amounts of DP&L's Generation assets that were transferred to AES Ohio Generation on October 1, 2017: $ in millions October 1, 2017 ASSETS Restricted cash $ 2.0 Accounts receivable, net 31.3 Inventories 42.0 Taxes applicable to subsequent years 1.8 Property, plant & equipment, net 87.0 Intangible assets, net 0.7 Other assets 15.5 Total assets $ 180.3 LIABILITIES Accounts payable $ 12.4 Accrued taxes (b) (3.9 ) Long-term debt (a) 0.3 Deferred taxes (b) (91.9 ) Pension, retiree and other benefits 9.6 Unamortized investment tax credit 15.1 Asset retirement obligations 126.3 Other liabilities 24.1 Total liabilities $ 92.0 Total accumulated other comprehensive income 2.1 Net assets transferred to AES Ohio Generation $ 86.2 (a) Long-term debt that transferred to AES Ohio Generation relates to capital leases. (b) Accrued taxes and deferred taxes transferred to AES Ohio Generation represent the tax asset position netted with liabilities on DP&L prior to Generation Separation. DP&L's generation business met the criteria to be classified as a discontinued operation, and, accordingly, the historical activity has been reclassified to "Discontinued operations" in the Statements of Operations for the years ended December 31, 2017 , 2016 and 2015 . Similarly, the assets and liabilities related to the generation business were classified as held-for-sale as of December 31, 2016. The following table summarizes the major categories of assets and liabilities at December 31, 2016, and the revenues, cost of revenues, operating and other expenses and income tax of discontinued operations for the periods indicated: December 31, $ in millions 2016 Restricted cash $ 29.0 Accounts receivable, net 34.9 Inventories 66.5 Taxes applicable to subsequent years 11.3 Property, plant & equipment, net 156.7 Intangible assets, net 0.9 Other assets 25.3 Total assets of the disposal group classified as held-for-sale in the balance sheets $ 324.6 Accounts payable $ 54.8 Accrued taxes 3.5 Long-term debt 13.4 Taxes payable 11.3 Deferred taxes (a) (120.7 ) Pension, retiree and other benefits 8.2 Unamortized investment tax credit 16.6 Asset retirement obligations 127.0 Other liabilities 43.6 Total liabilities of the disposal group classified as held-for-sale in the balance sheets $ 157.7 Years ended December 31, 2017 2016 2015 Revenues $ 358.4 $ 557.9 $ 901.6 Cost of revenues (191.6 ) (341.1 ) (698.3 ) Operating and other expenses (156.8 ) (202.0 ) (250.8 ) Fixed-asset impairment (66.3 ) (1,353.5 ) — Loss from discontinued operations (56.3 ) (1,338.7 ) (47.5 ) Income tax benefit from discontinued operations (15.9 ) (468.4 ) (23.9 ) Net loss from discontinued operations $ (40.4 ) $ (870.3 ) $ (23.6 ) (a) Deferred taxes represent the tax asset position netted with liabilities on DP&L prior to Generation Separation. |
Overview and Summary of Signi47
Overview and Summary of Significant Accounting Policies (Narrative) (Details) $ in Millions | Jan. 31, 2018employee | Sep. 30, 2017generating_facility | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($)mi²customergenerating_facilitysegment | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) |
Significant Accounting Policies [Line Items] | ||||||
Capitalized Software, estimated amortization expense for year after next | $ 4.2 | |||||
Number of reportable segments | segment | 2 | |||||
Service area, square miles | mi² | 6,000 | |||||
Number of coal fired power plants | generating_facility | 5 | 3 | ||||
Capitalized interest for unregulated generation property | $ 2.3 | $ 2.8 | $ 2 | |||
Straight-line depreciation average annual composite basis (percent) | 5.00% | 6.10% | 4.40% | |||
Depreciation and amortization | $ 106.9 | $ 132.3 | $ 134.6 | |||
Insurance and claims costs | 3 | 5.4 | ||||
Insurance costs below coverage thresholds of third-party providers | 11.9 | 10.9 | ||||
Investment in trust | $ 0.3 | 0.3 | ||||
Finite-Lived Intangible Asset, Useful Life | 7 years | |||||
Capitalized Computer Software, Amortization | $ 6.8 | 7.7 | 9 | |||
Capitalized Software, estimated amortization over remaining useful life | 17.2 | |||||
Capitalized Software, estimated amortization expense for next twelve months | 7.2 | |||||
Capitalized Software, estimated amortization expense for three years in the future | 2.7 | |||||
Capitalized Software, estimated amortization expense for four years in the future | 1.7 | |||||
Capitalized Software, estimated amortization expense for five years in the future | 1.4 | |||||
Increase (Decrease) in Restricted Cash | (27.1) | 11.8 | 0.4 | |||
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Significant Accounting Policies [Line Items] | ||||||
Payments of Ordinary Dividends, Common Stock | 39 | 70 | 50 | |||
Capitalized Software, estimated amortization expense for year after next | $ 3.1 | |||||
Approximate number of retail customers | customer | 521,000 | |||||
Service area, square miles | mi² | 6,000 | |||||
Number of coal fired power plants | generating_facility | 5 | |||||
Capitalized interest for unregulated generation property | $ 2 | $ 2.7 | $ 2 | |||
Straight-line depreciation average annual composite basis (percent) | 3.40% | 4.60% | 2.50% | |||
Depreciation and amortization | $ 75.3 | $ 71 | $ 71.5 | |||
Insurance costs below coverage thresholds of third-party providers | $ 4.4 | 3.9 | ||||
Finite-Lived Intangible Asset, Useful Life | 7 years | |||||
Capitalized Computer Software, Amortization | $ 5.7 | 6.7 | 7.2 | |||
Capitalized Software, estimated amortization over remaining useful life | 10.7 | |||||
Capitalized Software, estimated amortization expense for next twelve months | 5.1 | |||||
Capitalized Software, estimated amortization expense for three years in the future | 1.6 | |||||
Capitalized Software, estimated amortization expense for four years in the future | 0.6 | |||||
Capitalized Software, estimated amortization expense for five years in the future | 0.3 | |||||
Increase (Decrease) in Restricted Cash | (26.6) | 11.9 | 0.3 | |||
Note to DPL Capital Trust II Maturing in 2031 - 8.125% [Member] | ||||||
Significant Accounting Policies [Line Items] | ||||||
Note payable to trust | 15.6 | 15.6 | ||||
Subsequent Event [Member] | ||||||
Significant Accounting Policies [Line Items] | ||||||
Entity number of employees | employee | 1,060 | |||||
Employees under collective bargaining agreement (percent) | 60.00% | |||||
Subsequent Event [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Significant Accounting Policies [Line Items] | ||||||
Entity number of employees | employee | 660 | |||||
Percentage Of Employees Under Collective Bargaining Agreement | 53.00% | |||||
Electric Generation, Transmission and Distribution Equipment [Member] | ||||||
Significant Accounting Policies [Line Items] | ||||||
Depreciation and amortization | 100.1 | 124.6 | 125.6 | |||
Electric Generation, Transmission and Distribution Equipment [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Significant Accounting Policies [Line Items] | ||||||
Depreciation and amortization | 69.6 | 64.3 | 64.3 | |||
Pension [Member] | ||||||
Significant Accounting Policies [Line Items] | ||||||
Service cost | 5.7 | 5.7 | 7.1 | |||
Interest cost | 14.2 | 14.7 | 17.3 | |||
Pension [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Significant Accounting Policies [Line Items] | ||||||
Service cost | 5.7 | 5.7 | 7.1 | |||
Interest cost | 14.2 | 14.7 | $ 17.3 | |||
Pension [Member] | Scenario, Forecast [Member] | ||||||
Significant Accounting Policies [Line Items] | ||||||
Service cost | $ 7.5 | |||||
Pension [Member] | Scenario, Forecast [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Significant Accounting Policies [Line Items] | ||||||
Service cost | $ 7.5 | |||||
Adjustments for New Accounting Pronouncement [Member] | ||||||
Significant Accounting Policies [Line Items] | ||||||
Non-service Pension Costs | 1.9 | 1.8 | ||||
Increase (Decrease) in Restricted Cash | 27.1 | (11.8) | ||||
Adjustments for New Accounting Pronouncement [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Significant Accounting Policies [Line Items] | ||||||
Non-service Pension Costs | 7.2 | 7.8 | ||||
Increase (Decrease) in Restricted Cash | $ 26.6 | $ (11.9) |
Overview and Summary of Signi48
Overview and Summary of Significant Accounting Policies (Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Excise Taxes Collected | $ 49.4 | $ 50.9 | $ 49.9 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Excise Taxes Collected | $ 49.4 | $ 50.9 | $ 49.9 |
Supplemental Financial Inform49
Supplemental Financial Information (Supplemental Financial Information) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Supplemental Financial Information [Line Items] | |||
Unbilled revenue | $ 18 | $ 43 | |
Customer receivables | 57.8 | 73.9 | |
Amounts due from partners in jointly owned stations | 19.1 | 12.7 | |
Other | 4.9 | 6.7 | |
Provision for uncollectible accounts | (1.1) | (1.2) | |
Total accounts receivable, net | 98.7 | 135.1 | |
Fuel and Limestone | 15.5 | 38.9 | |
Plant materials and supplies | 8.5 | 36.6 | |
Other | 0.5 | 1.7 | |
Total inventories, at average cost | 24.5 | 77.2 | |
Assets held for sale - current | 250.3 | 0 | |
Gain (Loss) on Sale of Assets and Asset Impairment Charges | 2.2 | (49.2) | $ 0.4 |
Other Operating Income (Expense), Net | (6.6) | (0.1) | 0.4 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Supplemental Financial Information [Line Items] | |||
Unbilled revenue | 18 | 43 | |
Customer receivables | 44.2 | 45.9 | |
Amounts due from partners in jointly owned stations | 5 | 4 | |
Other | 4.7 | 8.1 | |
Provision for uncollectible accounts | (1.1) | (1.2) | |
Total accounts receivable, net | 70.8 | 99.8 | |
Plant materials and supplies | 6.9 | 6.9 | |
Other | 0.4 | 2.4 | |
Total inventories, at average cost | 7.3 | 9.3 | |
Assets held for sale - current | 0 | 324.6 | |
Gain (Loss) on Sale of Assets and Asset Impairment Charges | 15.7 | 0 | 0.4 |
Other Operating Income (Expense), Net | (0.5) | (0.4) | 0.1 |
Other Operating Income (Expense) [Member] | |||
Supplemental Financial Information [Line Items] | |||
Impaired Assets to be Disposed of by Method Other than Sale, Amount of Impairment Loss | 16.2 | 0 | 0 |
Gain (Loss) on Disposition of Business | (14) | 0 | 0 |
Insurance Recoveries | (8.7) | (0.7) | 0 |
Gain (Loss) on Sale of Assets and Asset Impairment Charges | 0 | (0.1) | 0.4 |
Other Cost and Expense, Operating | (0.1) | 0.7 | 0 |
Other Operating Income (Expense), Net | $ (6.6) | $ (0.1) | $ 0.4 |
Supplemental Financial Inform50
Supplemental Financial Information (Reclassification out of ACOI) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||
Other deductions | $ (113.9) | $ (109.4) | $ (121.5) |
Interest expense | (110.1) | (107.7) | (119.8) |
Revenue | 1,236.9 | 1,427.3 | 1,612.8 |
Purchased Power | (339.2) | (417.4) | (562.6) |
Tax expense (benefit) | 25.3 | 278.8 | (20) |
Income / (loss) from discontinued operations | 0 | (0.7) | 11.4 |
Income tax expense / (benefit) from discontinued operations | 0 | 19.2 | (1) |
Net income (loss) | (94.6) | (485.2) | (239) |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||
Other deductions | (32.1) | (24.5) | (33.2) |
Interest expense | (30.5) | (24.7) | (28.9) |
Revenue | 720 | 808 | 857 |
Purchased Power | (289.8) | (316.7) | (317.4) |
Tax expense (benefit) | (31.1) | (46) | (59) |
Income / (loss) from discontinued operations | (56.3) | (1,338.7) | (47.5) |
Income tax expense / (benefit) from discontinued operations | (15.9) | (468.4) | (23.9) |
Net income (loss) | 17 | (772.7) | 106.4 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||
Net income (loss) | (7.1) | (28.7) | (9.8) |
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) | (1.8) | (24.1) | (6.1) |
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 deductions | (0.1) | 0 | 0 |
Tax expense (benefit) | 0 | 0 | 0 |
Net income (loss) | (0.1) | 0 | 0 |
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 deductions | (0.1) | 0 | 0 |
Tax expense (benefit) | 0 | 0 | 0 |
Net income (loss) | (0.1) | 0 | 0 |
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) |
Revenue | (15.2) | (55.3) | (18.7) |
Purchased Power | 3.8 | 9.9 | 4.4 |
Total before income taxes | (12.4) | (46.4) | (15.4) |
Tax expense (benefit) | 4.4 | 16.7 | 5.4 |
Net income (loss) | (8) | (29.7) | (10) |
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 | (0.9) | (1) | (1.1) |
Tax expense (benefit) | 0.2 | 0.2 | 0.2 |
Income / (loss) from discontinued operations | (8.5) | (45.4) | (14.3) |
Income tax expense / (benefit) from discontinued operations | (3) | (16.2) | (5.4) |
Net income (loss) | (6.2) | (30) | (9.8) |
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 deductions | 1.5 | 1.6 | 0.4 |
Tax expense (benefit) | (0.5) | (0.6) | (0.2) |
Net income (loss) | 1 | 1 | 0.2 |
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 deductions | 6.8 | 7.7 | 5.6 |
Tax expense (benefit) | (2.3) | (1.8) | (1.9) |
Net income (loss) | $ 4.5 | $ 5.9 | $ 3.7 |
Supplemental Financial Inform51
Supplemental Financial Information (Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
AOCI Attributable to Parent, Net of Tax [Roll Forward] | |||
Balance, beginning of period | $ 0.3 | $ 17.4 | |
Other comprehensive income / (loss) before reclassifications | 7.6 | 11.6 | |
Amounts reclassified from accumulated other comprehensive income / (loss) | (7.1) | (28.7) | |
Other comprehensive income / (loss) | 0.5 | (17.1) | $ 9.9 |
Balance, end of period | 0.8 | 0.3 | 17.4 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | |||
Balance, beginning of period | (42.5) | (28.7) | |
Other comprehensive income / (loss) before reclassifications | 10.2 | 10.3 | |
Stockholders' Equity Note, Spinoff Transaction | (88.3) | ||
Amounts reclassified from accumulated other comprehensive income / (loss) | (1.8) | (24.1) | |
Other comprehensive income / (loss) | 8.4 | (13.8) | 13.6 |
Balance, end of period | (36.2) | (42.5) | (28.7) |
Accumulated Net Investment Gain (Loss) Attributable to Parent [Member] | |||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | |||
Balance, beginning of period | 0.6 | 0.4 | |
Other comprehensive income / (loss) before reclassifications | 0.5 | 0.2 | |
Amounts reclassified from accumulated other comprehensive income / (loss) | (0.1) | 0 | |
Other comprehensive income / (loss) | 0.4 | 0.2 | |
Balance, end of period | 1 | 0.6 | 0.4 |
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 | 0.7 | 0.5 | |
Other comprehensive income / (loss) before reclassifications | 0.5 | 0.2 | |
Amounts reclassified from accumulated other comprehensive income / (loss) | (0.1) | 0 | |
Other comprehensive income / (loss) | 0.4 | 0.2 | |
Balance, end of period | 1.1 | 0.7 | 0.5 |
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 | 13.1 | 26.7 | |
Other comprehensive income / (loss) before reclassifications | 9.6 | 16.1 | |
Amounts reclassified from accumulated other comprehensive income / (loss) | (8) | (29.7) | |
Other comprehensive income / (loss) | 1.6 | (13.6) | |
Balance, end of period | 14.7 | 13.1 | 26.7 |
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 | (2.7) | 11.2 | |
Other comprehensive income / (loss) before reclassifications | 12.4 | 16.1 | |
Stockholders' Equity Note, Spinoff Transaction | (2.1) | ||
Amounts reclassified from accumulated other comprehensive income / (loss) | (6.2) | (30) | |
Other comprehensive income / (loss) | 6.2 | (13.9) | |
Balance, end of period | 1.4 | (2.7) | 11.2 |
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] | |||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | |||
Balance, beginning of period | (13.4) | (9.7) | |
Other comprehensive income / (loss) before reclassifications | (2.5) | (4.7) | |
Amounts reclassified from accumulated other comprehensive income / (loss) | 1 | 1 | |
Other comprehensive income / (loss) | (1.5) | (3.7) | |
Balance, end of period | (14.9) | (13.4) | (9.7) |
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 | (40.5) | (40.4) | |
Other comprehensive income / (loss) before reclassifications | (2.7) | (6) | |
Amounts reclassified from accumulated other comprehensive income / (loss) | 4.5 | 5.9 | |
Other comprehensive income / (loss) | 1.8 | (0.1) | |
Balance, end of period | $ (38.7) | $ (40.5) | $ (40.4) |
Regulatory Assets and Liabili52
Regulatory Assets and Liabilities (Narrative) (Details) - USD ($) $ in Millions | Oct. 20, 2017 | Jan. 30, 2017 | Dec. 31, 2017 | Dec. 31, 2016 |
Regulatory assets earning a return | $ 12.5 | |||
Distribution Modernization Rider | $ 105 | |||
Return on Equity SEET Threshold | 12.00% | |||
Distribution Modernization Rider Period | 3 years | |||
Regulatory Assets | $ 187.1 | $ 204 | ||
Regulatory Liabilities | 236 | 164.1 | ||
Regulatory assets, non-current | $ 163.2 | 203.9 | ||
Tax rate before change due to Tax Cuts and Jobs Act of 2017 | 35.00% | |||
Regulatory liabilities, non-current | $ 221.2 | 130.4 | ||
Deferred Income Tax Charge [Member] | ||||
Regulatory assets, non-current | 0 | 35.9 | ||
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Regulatory assets earning a return | $ 12.5 | |||
Distribution Modernization Rider | $ 105 | |||
Return on Equity SEET Threshold | 12.00% | |||
Distribution Modernization Rider Period | 3 years | |||
Regulatory Assets | $ 187.1 | 204 | ||
Regulatory Liabilities | 236 | 164.1 | ||
Regulatory assets, non-current | $ 163.2 | 203.9 | ||
Tax rate before change due to Tax Cuts and Jobs Act of 2017 | 35.00% | |||
Regulatory liabilities, non-current | $ 221.2 | 130.4 | ||
THE DAYTON POWER AND LIGHT COMPANY [Member] | Deferred Income Tax Charge [Member] | ||||
Regulatory assets, non-current | 0 | 35.9 | ||
Deferred Income Tax Charge [Member] | ||||
Regulatory liabilities, non-current | 83.4 | 0 | ||
Deferred Income Tax Charge [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Regulatory liabilities, non-current | $ 83.4 | $ 0 |
Regulatory Assets and Liabili53
Regulatory Assets and Liabilities (Schedule of Regulatory Assets and Liabilities) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Total current regulatory assets | $ 23.9 | $ 0.1 |
Total non-current regulatory assets | 163.2 | 203.9 |
Total regulatory assets | 187.1 | 204 |
Total current regulatory liabilities | 14.8 | 33.7 |
Total non-current regulatory liabilities | 221.2 | 130.4 |
Total regulatory liabilities | $ 236 | 164.1 |
Overcollection of costs to be refunded [Member] | ||
Regulatory Liabilities Type of Recovery | A/B | |
Total non-current regulatory liabilities | $ 14.8 | 33.7 |
Regulatory Liability, Amortization Through | 2,018 | |
Postretirement benefits [Member] | ||
Regulatory Liabilities Type of Recovery | B | |
Total non-current regulatory liabilities | $ 5 | 3.9 |
Regulatory Liability, Amortization Through | Ongoing | |
Removal Costs [Member] | ||
Total non-current regulatory liabilities | $ 132.8 | 126.5 |
Regulatory Liability, Amortization Through | Not Applicable | |
Deferred Income Tax Charge [Member] | ||
Total non-current regulatory liabilities | $ 83.4 | 0 |
Regulatory Liability, Amortization Through | Various | |
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total current regulatory assets | $ 23.9 | 0.1 |
Total non-current regulatory assets | 163.2 | 203.9 |
Total regulatory assets | 187.1 | 204 |
Total current regulatory liabilities | 14.8 | 33.7 |
Total non-current regulatory liabilities | 221.2 | 130.4 |
Total regulatory liabilities | $ 236 | 164.1 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Overcollection of costs to be refunded [Member] | ||
Regulatory Liabilities Type of Recovery | A/B | |
Total non-current regulatory liabilities | $ 14.8 | 33.7 |
Regulatory Liability, Amortization Through | 2,018 | |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Postretirement benefits [Member] | ||
Regulatory Liabilities Type of Recovery | B | |
Total non-current regulatory liabilities | $ 5 | 3.9 |
Regulatory Liability, Amortization Through | Ongoing | |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Removal Costs [Member] | ||
Total non-current regulatory liabilities | $ 132.8 | 126.5 |
Regulatory Liability, Amortization Through | Not Applicable | |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Deferred Income Tax Charge [Member] | ||
Total non-current regulatory liabilities | $ 83.4 | 0 |
Regulatory Liability, Amortization Through | Various | |
Undercollections to be collected [Member] | ||
Type of Recovery | A/B | |
Amortization Through | 2,018 | |
Total current regulatory assets | $ 23.9 | 0.1 |
Undercollections to be collected [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Type of Recovery | A/B | |
Amortization Through | 2,018 | |
Total current regulatory assets | $ 23.9 | 0.1 |
Pension benefits [Member] | ||
Type of Recovery | B | |
Amortization Through | Ongoing | |
Total non-current regulatory assets | $ 92.4 | 97.6 |
Pension benefits [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Type of Recovery | B | |
Amortization Through | Ongoing | |
Total non-current regulatory assets | $ 92.4 | 97.6 |
Deferred Income Tax Charge [Member] | ||
Type of Recovery | B/C | |
Amortization Through | Ongoing | |
Total non-current regulatory assets | $ 0 | 35.9 |
Deferred Income Tax Charge [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Type of Recovery | B/C | |
Amortization Through | Ongoing | |
Total non-current regulatory assets | $ 0 | 35.9 |
Fuel costs [Member] | ||
Type of Recovery | B | |
Amortization Through | 2,020 | |
Total non-current regulatory assets | $ 9.3 | 15.4 |
Fuel costs [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Type of Recovery | B | |
Amortization Through | 2,020 | |
Total non-current regulatory assets | $ 9.3 | 15.4 |
Deferred Regulatory Compliance Costs [Member] | ||
Type of Recovery | B | |
Amortization Through | 2,020 | |
Total non-current regulatory assets | $ 9.2 | 12.4 |
Deferred Regulatory Compliance Costs [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Type of Recovery | B | |
Amortization Through | 2,020 | |
Total non-current regulatory assets | $ 9.2 | 12.4 |
Unrecovered OVEC charges [Member] | ||
Type of Recovery | D | |
Amortization Through | Undetermined | |
Total non-current regulatory assets | $ 27.8 | 21 |
Unrecovered OVEC charges [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Type of Recovery | D | |
Amortization Through | Undetermined | |
Total non-current regulatory assets | $ 27.8 | 21 |
Unamortized loss on reacquired debt [Member] | ||
Type of Recovery | B | |
Amortization Through | Various | |
Total non-current regulatory assets | $ 7 | 8 |
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 | $ 7 | 8 |
Smart grid and advanced metering infrastructure costs [Member] | ||
Type of Recovery | B | |
Amortization Through | Undetermined | |
Total non-current regulatory assets | $ 7.3 | 7.3 |
Smart grid and advanced metering infrastructure costs [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Type of Recovery | B | |
Amortization Through | Undetermined | |
Total non-current regulatory assets | $ 7.3 | 7.3 |
Rate case costs [Member] | ||
Type of Recovery | B | |
Amortization Through | Undetermined | |
Total non-current regulatory assets | $ 8.1 | 6.3 |
Rate case costs [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Type of Recovery | B | |
Amortization Through | Undetermined | |
Total non-current regulatory assets | $ 8.1 | 6.3 |
Storm Costs [Member] | ||
Type of Recovery | A | |
Amortization Through | Undetermined | |
Total non-current regulatory assets | $ 2.1 | 0 |
Storm Costs [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Type of Recovery | A | |
Amortization Through | Undetermined | |
Total non-current regulatory assets | $ 2.1 | $ 0 |
Property, Plant and Equipment w
Property, Plant and Equipment with Corresponding Depreciation Rates (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Public Utility, Property, Plant and Equipment [Line Items] | |||
Total property, plant and equipment in service | $ 1,554.7 | $ 1,985.6 | |
Total property, plant and equipment in service, Composite Rate | 5.00% | 6.10% | 4.40% |
Regulated Operation [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Transmission | $ 242.7 | $ 247.3 | |
Distribution | 1,197.5 | 1,141.1 | |
General | 13.7 | 13.7 | |
Non-depreciable | 64.7 | 63.5 | |
Total property, plant and equipment in service | $ 1,518.6 | $ 1,465.6 | |
Transmission, Composite Rate | 4.00% | 3.90% | |
Distribution, Composite Rate | 4.90% | 4.70% | |
General, Composite Rate | 7.10% | 7.40% | |
Unregulated Operation [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Non-depreciable | $ 5.8 | $ 19.8 | |
Total property, plant and equipment in service | 36.1 | 520 | |
Production / Generation | $ 10.9 | $ 483.2 | |
Production/Generation, Composite Rate | 63.20% | 11.70% | |
Other | $ 19.4 | $ 17 | |
Other, Composite Rate | 7.00% | 8.00% | |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Total property, plant and equipment in service | $ 2,247.2 | $ 2,213.5 | |
Total property, plant and equipment in service, Composite Rate | 3.40% | 4.60% | 2.50% |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Regulated Operation [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Transmission | $ 414.6 | $ 421.1 | |
Distribution | 1,735.9 | 1,693.5 | |
General | 31.2 | 31.6 | |
Non-depreciable | 64.6 | 63.5 | |
Total property, plant and equipment in service | $ 2,246.3 | $ 2,209.7 | |
Transmission, Composite Rate | 2.40% | 2.30% | |
Distribution, Composite Rate | 3.40% | 3.20% | |
General, Composite Rate | 3.10% | 3.20% | |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Unregulated Operation [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Non-depreciable | $ 0.9 | $ 3.8 | |
Production / Generation | $ 0.2 | $ 0.3 | |
Production/Generation, Composite Rate | 2.70% | 2.70% | |
Other | $ 0.7 | $ 3.5 |
Property, Plant and Equipment55
Property, Plant and Equipment (Narrative) (Details) $ in Millions | 6 Months Ended | 9 Months Ended | 12 Months Ended | ||
Dec. 31, 2016USD ($) | Sep. 30, 2017generating_facilityMW | Dec. 31, 2017USD ($)generating_facility | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Jointly Owned Utility Plant Interests [Line Items] | |||||
Number of generating facilities | generating_facility | 5 | 3 | |||
Fixed-asset impairment (Note 15) | $ 623.5 | $ 175.8 | $ 859 | $ 0 | |
Estimated costs of removal | 126.5 | $ 132.8 | 126.5 | 121.8 | |
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) | $ 66.3 | 1,353.5 | 0 | ||
Estimated costs of removal | $ 126.5 | $ 132.8 | $ 126.5 | $ 121.8 | |
Stuart Station Unit 1 [Member] | |||||
Jointly Owned Utility Plant Interests [Line Items] | |||||
Production Plan Capacity | MW | 202 |
Property, Plant and Equipment56
Property, Plant and Equipment (Ownership Interests) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2017USD ($)MW | |
Conesville [Member] | |
Ownership (%) | 16.50% |
Production Plan Capacity | MW | 129 |
Gross Plant In Service | $ 1 |
Accumulated Depreciation | 1 |
Construction Work in Process | $ 2 |
Killen Station [Member] | |
Ownership (%) | 67.00% |
Production Plan Capacity | MW | 402 |
Gross Plant In Service | $ 10 |
Accumulated Depreciation | 8 |
Construction Work in Process | $ 0 |
Stuart Station - Units 2-4 [Member] | |
Ownership (%) | 35.00% |
Stuart Station [Member] | |
Production Plan Capacity | MW | 606 |
Gross Plant In Service | $ 2 |
Accumulated Depreciation | 2 |
Construction Work in Process | 0 |
Electric Transmission [Member] | |
Gross Plant In Service | 46 |
Accumulated Depreciation | 13 |
Construction Work in Process | $ 0 |
Total Jointly Owned Stations [Member] | |
Production Plan Capacity | MW | 1,137 |
Gross Plant In Service | $ 58 |
Accumulated Depreciation | 24 |
Construction Work in Process | $ 2 |
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, 2017 | Dec. 31, 2016 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Balance at January 1 | $ 138.8 | $ 65.9 |
Additions | 0.1 | 70.2 |
Asset Retirement Obligation, Revision of Estimate | (6.3) | |
Accretion expense | 3.7 | 2.7 |
Settlements | (0.1) | 0 |
Balance at December 31 | 131.2 | 138.8 |
Asset Retirement Obligation, Reduction Due to Plants Sold or Held-for-sale | (5) | |
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Balance at January 1 | 8.2 | 5 |
Additions | 2.7 | |
Accretion expense | 0.1 | 0.3 |
Settlements | (0.3) | 0.2 |
Balance at December 31 | $ 8 | $ 8.2 |
Property, Plant and Equipment58
Property, Plant and Equipment (Changes in the Liability for Transmission and Distribution Asset Removal Costs) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Changes in Liability for Transmission and Distribution Asset Removal Costs [Roll Forward] | ||
Balance at January 1 | $ 126.5 | $ 121.8 |
Additions | 12 | 11.7 |
Settlements | (5.7) | (7) |
Balance at December 31 | 132.8 | 126.5 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Changes in Liability for Transmission and Distribution Asset Removal Costs [Roll Forward] | ||
Balance at January 1 | 126.5 | 121.8 |
Additions | 12 | 11.7 |
Settlements | (5.7) | (7) |
Balance at December 31 | $ 132.8 | $ 126.5 |
Fair Value Measurements (Narrat
Fair Value Measurements (Narrative) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Debt maturity date, earliest | 2,019 | |
Debt maturity date, latest | 2,061 | |
Unrealized gains and immaterial losses on Master Trust assets in AOCI | $ 1.6 | $ 1 |
Unrealized gains and immaterial losses on Master Trust assets in AOCI, after tax | $ 1 | 0.6 |
Percent of inputs to the fair value of derivative instruments from quoted market prices | 98.70% | |
Gross additions to our existing landfill and asbestos AROs | $ (2.6) | 72.9 |
Gross additions to our existing landfill and asbestos AROs, after tax | (1.7) | 47.4 |
Available-for-sale Securities, Gross Realized Gains (Losses), Sale Proceeds | 0.9 | |
AvailableForSaleSecuritiesGross Realized Gains Losses Sale Proceeds Net of Tax | 0.6 | |
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Unrealized gains and immaterial losses on Master Trust assets in AOCI | 1.7 | 1.1 |
Unrealized gains and immaterial losses on Master Trust assets in AOCI, after tax | $ 1.1 | 0.7 |
Percent of inputs to the fair value of derivative instruments from quoted market prices | 100.00% | |
Gross additions to our existing landfill and asbestos AROs | $ (0.2) | 3.2 |
Gross additions to our existing landfill and asbestos AROs, after tax | (0.1) | $ 2.1 |
Available-for-sale Securities, Gross Realized Gains (Losses), Sale Proceeds | 0.9 | |
AvailableForSaleSecuritiesGross Realized Gains Losses Sale Proceeds Net of Tax | 0.6 | |
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 |
Fair Value Measurements (Fair V
Fair Value Measurements (Fair Value and Cost of Non-Derivative Instruments) (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Hedge Funds [Member] | ||
Total Master Trust Assets, Fair Value | $ 0 | |
Carrying Value [Member] | ||
Total Assets | $ 7.3 | 7.6 |
Carrying Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Assets | 7.3 | 7.6 |
Carrying Value [Member] | Money Market Funds [Member] | ||
Total Master Trust Assets, Cost | 0.3 | 0.4 |
Carrying Value [Member] | Money Market Funds [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Cost | 0.3 | 0.4 |
Carrying Value [Member] | Equity Securities [Member] | ||
Total Master Trust Assets, Cost | 2.5 | 2.4 |
Carrying Value [Member] | Equity Securities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Cost | 2.5 | 2.4 |
Carrying Value [Member] | Debt Securities [Member] | ||
Total Master Trust Assets, Cost | 4.3 | 4.4 |
Carrying Value [Member] | Debt Securities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Cost | 4.3 | 4.4 |
Carrying Value [Member] | Hedge Funds [Member] | ||
Total Master Trust Assets, Cost | 0.1 | 0 |
Carrying Value [Member] | Hedge Funds [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Cost | 0.1 | 0 |
Carrying Value [Member] | Real Estate Funds [Member] | ||
Total Master Trust Assets, Cost | 0 | 0.3 |
Carrying Value [Member] | Real Estate Funds [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Cost | 0 | 0.3 |
Carrying Value [Member] | Tangible Assets [Member] | ||
Total Master Trust Assets, Cost | 0.1 | 0.1 |
Carrying Value [Member] | Tangible Assets [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Cost | 0.1 | 0.1 |
Carrying Value [Member] | Debt [Member] | ||
Long-term Debt | 1,704.8 | 1,858.4 |
Carrying Value [Member] | Debt [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Long-term Debt | 646.6 | 735.7 |
Fair Value [Member] | ||
Total Master Trust Assets, Fair Value | 9.1 | 8.7 |
Total Assets | 9.1 | 8.7 |
Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 9.1 | |
Total Assets | 9.1 | 8.7 |
Fair Value [Member] | Money Market Funds [Member] | ||
Total Master Trust Assets, Fair Value | 0.3 | 0.4 |
Fair Value [Member] | Money Market Funds [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0.3 | 0.4 |
Fair Value [Member] | Equity Securities [Member] | ||
Total Master Trust Assets, Fair Value | 4.2 | 3.4 |
Fair Value [Member] | Equity Securities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 4.2 | 3.4 |
Fair Value [Member] | Debt Securities [Member] | ||
Total Master Trust Assets, Fair Value | 4.3 | 4.4 |
Fair Value [Member] | Debt Securities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 4.3 | 4.4 |
Fair Value [Member] | Hedge Funds [Member] | ||
Total Master Trust Assets, Fair Value | 0.2 | 0.1 |
Fair Value [Member] | Hedge Funds [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0.2 | 0.1 |
Fair Value [Member] | Real Estate Funds [Member] | ||
Total Master Trust Assets, Fair Value | 0 | 0.3 |
Fair Value [Member] | Real Estate Funds [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0 | 0.3 |
Fair Value [Member] | Tangible Assets [Member] | ||
Total Master Trust Assets, Fair Value | 0.1 | 0.1 |
Fair Value [Member] | Tangible Assets [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0.1 | 0.1 |
Fair Value [Member] | Debt [Member] | ||
Debt, Fair Value | 1,819.3 | 1,907.7 |
Fair Value [Member] | Debt [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Debt, Fair Value | $ 658.4 | $ 750.1 |
Fair Value Measurements (Fair61
Fair Value Measurements (Fair Value of Assets and Liabilities Measured on Recurring Basis) (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Fair Value, Inputs, Level 1 [Member] | ||
Total Master Trust Assets, Fair Value | $ 0.3 | $ 0.4 |
Total Derivative Assets | 0.2 | 0 |
Total Assets | 0.5 | 0.4 |
Total Derivative Liabilities | 0.1 | 0 |
Total Liabilities | 0.1 | 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 | 0 |
Total Derivative Liabilities | 0 | |
Fair Value, Inputs, Level 1 [Member] | Commodity Contract - FTR [Member] | ||
Total Derivative Assets | 0 | |
Total Derivative Liabilities | 0 | |
Fair Value, Inputs, Level 1 [Member] | Natural Gas [Member] | ||
Total Derivative Assets | 0.2 | |
Total Derivative Liabilities | 0.1 | |
Fair Value, Inputs, Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0.3 | |
Total Derivative Assets | 0 | |
Total Assets | 0.3 | 0.4 |
Debt Instrument, Fair Value Disclosure | 0 | |
Total Liabilities | 0 | 0 |
Fair Value, Inputs, Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Interest Rate Contract [Member] | ||
Total Derivative Assets | 0 | |
Fair Value, Inputs, Level 2 [Member] | ||
Total Master Trust Assets, Fair Value | 8.8 | 8.3 |
Total Derivative Assets | 12.6 | 20.7 |
Total Assets | 21.4 | 29 |
Total Derivative Liabilities | 14.9 | 26.7 |
Total Liabilities | 1,816.4 | 1,916.4 |
Fair Value, Inputs, Level 2 [Member] | Forward Contract Power [Member] | ||
Total Derivative Assets | 10.8 | 19.5 |
Total Derivative Liabilities | 14.9 | 26 |
Fair Value, Inputs, Level 2 [Member] | Interest Rate Contract [Member] | ||
Total Derivative Assets | 1.8 | 1.2 |
Total Derivative Liabilities | 0.7 | |
Fair Value, Inputs, Level 2 [Member] | Commodity Contract - FTR [Member] | ||
Total Derivative Assets | 0 | |
Total Derivative Liabilities | 0 | |
Fair Value, Inputs, Level 2 [Member] | Natural Gas [Member] | ||
Total Derivative Assets | 0 | |
Total Derivative Liabilities | 0 | |
Fair Value, Inputs, Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 8.8 | |
Total Derivative Assets | 1.8 | |
Total Assets | 10.6 | 8.3 |
Debt Instrument, Fair Value Disclosure | 732.1 | |
Total Liabilities | 640.6 | 732.1 |
Fair Value, Inputs, Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Interest Rate Contract [Member] | ||
Total Derivative Assets | 1.8 | |
Fair Value, Inputs, Level 3 [Member] | ||
Total Master Trust Assets, Fair Value | 0 | 0 |
Total Derivative Assets | 0 | 0.1 |
Total Assets | 0 | 0.1 |
Total Derivative Liabilities | 0.3 | 2.5 |
Total Liabilities | 18.1 | 20.5 |
Fair Value, Inputs, Level 3 [Member] | Forward Contract Power [Member] | ||
Total Derivative Assets | 0 | 0 |
Total Derivative Liabilities | 0 | 2.5 |
Fair Value, Inputs, Level 3 [Member] | Interest Rate Contract [Member] | ||
Total Derivative Assets | 0 | 0 |
Total Derivative Liabilities | 0 | |
Fair Value, Inputs, Level 3 [Member] | Commodity Contract - FTR [Member] | ||
Total Derivative Assets | 0.1 | |
Total Derivative Liabilities | 0.3 | |
Fair Value, Inputs, Level 3 [Member] | Natural Gas [Member] | ||
Total Derivative Assets | 0 | |
Total Derivative Liabilities | 0 | |
Fair Value, Inputs, Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Assets | 0 | |
Debt Instrument, Fair Value Disclosure | 18 | |
Total Liabilities | 17.8 | 18 |
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 | 4.2 | 3.4 |
Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 4.2 | 3.4 |
Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Total Master Trust Assets, Fair Value | 0 | 0 |
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 | 4.3 | 4.4 |
Debt Securities [Member] | Fair Value, Inputs, Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 4.3 | 4.4 |
Debt Securities [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Total Master Trust Assets, Fair Value | 0 | 0 |
Money Market Funds [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Total Master Trust Assets, Fair Value | 0.3 | 0.4 |
Money Market Funds [Member] | Fair Value, Inputs, Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0.3 | 0.4 |
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 |
Money Market Funds [Member] | Fair Value, Inputs, Level 3 [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 | 0.2 | 0.1 |
Hedge Funds [Member] | Fair Value, Inputs, Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0.2 | 0.1 |
Hedge Funds [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Total Master Trust Assets, Fair Value | 0 | 0 |
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 | 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 | 0.3 |
Real Estate Funds [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Total Master Trust Assets, Fair Value | 0 | 0 |
Tangible Assets [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Total Master Trust Assets, Fair Value | 0 | 0 |
Tangible Assets [Member] | Fair Value, Inputs, Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0 | 0 |
Tangible Assets [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Total Master Trust Assets, Fair Value | 0.1 | 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 | 0.1 |
Tangible Assets [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Total Master Trust Assets, Fair Value | 0 | 0 |
Debt [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Debt Instrument, Fair Value Disclosure | 0 | 0 |
Debt [Member] | Fair Value, Inputs, Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Debt Instrument, Fair Value Disclosure | 0 | |
Debt [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Debt Instrument, Fair Value Disclosure | 1,801.5 | 1,889.7 |
Debt [Member] | Fair Value, Inputs, Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Debt Instrument, Fair Value Disclosure | 640.6 | |
Debt [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Debt Instrument, Fair Value Disclosure | 17.8 | 18 |
Debt [Member] | Fair Value, Inputs, Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Debt Instrument, Fair Value Disclosure | 17.8 | |
Fair Value [Member] | ||
Total Master Trust Assets, Fair Value | 9.1 | 8.7 |
Total Derivative Assets | 12.8 | 20.8 |
Total Assets | 21.9 | 29.5 |
Total Derivative Liabilities | 15.3 | 29.2 |
Total Liabilities | 1,834.6 | 1,936.9 |
Fair Value [Member] | Forward Contract Power [Member] | ||
Total Derivative Assets | 10.8 | 19.5 |
Total Derivative Liabilities | 14.9 | 28.5 |
Fair Value [Member] | Interest Rate Contract [Member] | ||
Total Derivative Assets | 1.8 | 1.2 |
Total Derivative Liabilities | 0.7 | |
Fair Value [Member] | Commodity Contract - FTR [Member] | ||
Total Derivative Assets | 0.1 | |
Total Derivative Liabilities | 0.3 | |
Fair Value [Member] | Natural Gas [Member] | ||
Total Derivative Assets | 0.2 | |
Total Derivative Liabilities | 0.1 | |
Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 9.1 | |
Total Derivative Assets | 1.8 | |
Total Assets | 10.9 | 8.7 |
Total Liabilities | 658.4 | 750.1 |
Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Interest Rate Contract [Member] | ||
Total Derivative Assets | 1.8 | |
Fair Value [Member] | Equity Securities [Member] | ||
Total Master Trust Assets, Fair Value | 4.2 | 3.4 |
Fair Value [Member] | Equity Securities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 4.2 | 3.4 |
Fair Value [Member] | Debt Securities [Member] | ||
Total Master Trust Assets, Fair Value | 4.3 | 4.4 |
Fair Value [Member] | Debt Securities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 4.3 | 4.4 |
Fair Value [Member] | Money Market Funds [Member] | ||
Total Master Trust Assets, Fair Value | 0.3 | 0.4 |
Fair Value [Member] | Money Market Funds [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0.3 | 0.4 |
Fair Value [Member] | Hedge Funds [Member] | ||
Total Master Trust Assets, Fair Value | 0.2 | 0.1 |
Fair Value [Member] | Hedge Funds [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0.2 | 0.1 |
Fair Value [Member] | Real Estate Funds [Member] | ||
Total Master Trust Assets, Fair Value | 0 | 0.3 |
Fair Value [Member] | Real Estate Funds [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0 | 0.3 |
Fair Value [Member] | Tangible Assets [Member] | ||
Total Master Trust Assets, Fair Value | 0.1 | 0.1 |
Fair Value [Member] | Tangible Assets [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0.1 | 0.1 |
Fair Value [Member] | Debt [Member] | ||
Debt Instrument, Fair Value Disclosure | 1,819.3 | 1,907.7 |
Fair Value [Member] | Debt [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Debt Instrument, Fair Value Disclosure | $ 658.4 | $ 750.1 |
Fair Value Measurements (Fair62
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 | Dec. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Jun. 30, 2016 | Sep. 30, 2015 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||
Carrying Value | $ 1,767.2 | $ 1,324.9 | $ 1,767.2 | |||||
Fixed-asset impairment (Note 15) | 623.5 | 175.8 | 859 | $ 0 | ||||
Goodwill impairment | 0 | 0 | 317 | |||||
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||
Carrying Value | 1,283.9 | 1,301.4 | 1,283.9 | |||||
Fixed-asset impairment (Note 15) | 66.3 | 1,353.5 | $ 0 | |||||
Goodwill | $ 317 | |||||||
Goodwill impairment | $ 317 | $ 317 | ||||||
AES Ohio Generation peakers [Member] | ||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||
Carrying Value | 346.9 | |||||||
AES Ohio Generation 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 | |||||||
AES Ohio Generation 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 | |||||||
AES Ohio Generation 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 | 237.5 | |||||||
Killen [Member] | ||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||
Carrying Value | 118.2 | 35.2 | 118.2 | $ 315.1 | ||||
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 | 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 | 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 | 84.3 | 84.3 | ||||||
Stuart [Member] | ||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||
Carrying Value | 285.9 | 42.4 | 285.9 | |||||
Fixed-asset impairment (Note 15) | 175.8 | |||||||
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 | 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 | 0 | |||||
Miami Fort [Member] | ||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||
Carrying Value | 185.9 | 185.9 | ||||||
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 | ||||||
Zimmer [Member] | ||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||
Carrying Value | 168.4 | 168.4 | ||||||
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 | ||||||
Conesville [Member] | ||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||
Carrying Value | 25 | 25 | ||||||
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 | ||||||
Hutchings Peakers [Member] | ||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||
Carrying Value | 3.2 | 3.2 | ||||||
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 | ||||||
Peaking Generating Facilities [Member] | ||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||
Carrying Value | 9.9 | |||||||
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 | |||||||
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 | |||||||
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 | $ 5.2 |
Fair Value Measurements (Signif
Fair Value Measurements (Significant unobservable inputs, nonrecurring) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |
Dec. 31, 2016 | Jun. 30, 2016 | Dec. 31, 2017 | |
Income Approach Valuation Technique [Member] | Minimum [Member] | Conesville [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | (19.30%) | ||
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | (54.30%) | ||
Income Approach Valuation Technique [Member] | Minimum [Member] | Stuart [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | (11.90%) | ||
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | (61.40%) | ||
Income Approach Valuation Technique [Member] | Minimum [Member] | Killen [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | (14.20%) | (11.00%) | |
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | (56.60%) | (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) | (19.50%) | ||
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | (40.30%) | ||
Income Approach Valuation Technique [Member] | Maximum [Member] | Conesville [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | 10.90% | ||
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | 99.40% | ||
Income Approach Valuation Technique [Member] | Maximum [Member] | Stuart [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | 1.10% | ||
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | 75.10% | ||
Income Approach Valuation Technique [Member] | Maximum [Member] | Killen [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | 2.90% | 13.00% | |
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | 42.40% | 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) | (25.90%) | ||
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | 63.10% | ||
Income Approach Valuation Technique [Member] | Weighted Average [Member] | Conesville [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | 0.60% | ||
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | 20.20% | ||
Income Approach Valuation Technique [Member] | Weighted Average [Member] | Stuart [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Annual revenue growth (percent) | (4.70%) | ||
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | 8.00% | 10.00% | |
Fair Value Inputs, Discount Rate | 10.00% | 7.00% | |
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 | (15.50%) | 6.00% | 22.00% |
Fair Value Inputs, Discount Rate | 10.00% | 11.00% | 7.00% |
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) | (0.70%) | ||
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent | 12.10% | ||
Fair Value Inputs, Discount Rate | 7.00% | ||
Fair Value, Inputs, Level 3 [Member] | AES Ohio Generation peakers [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Long-lived assets held and used, fair value | $ 237.5 | ||
Fair Value, Inputs, Level 3 [Member] | Killen [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Long-lived assets held and used, fair value | $ 84.3 | ||
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 |
Derivative Instruments and He64
Derivative Instruments and Hedging Activities (Narrative) (Details) - USD ($) | Dec. 31, 2017 | Dec. 31, 2016 |
Fair value of commodity derivative instruments | $ 15,300,000 | |
Collateral Already Posted, Aggregate Fair Value | 8,700,000 | |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 1,400,000 | |
Collateral if debt were to fall below investment grade | 4,900,000 | |
Tax-exempt First Mortgage Bonds - rates from: 1.52% - 1.92% (a) and 1.29% - 1.42% (b) | ||
Long-term Debt, Gross | 200,000,000 | $ 200,000,000 |
Tax-exempt First Mortgage Bonds - rates from: 1.52% - 1.92% (a) and 1.29% - 1.42% (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 | $ 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 He65
Derivative Instruments and Hedging Activities (Outstanding Derivative Instruments) (Details) | 12 Months Ended | ||
Dec. 31, 2017USD ($)MMBTUMWh | Dec. 31, 2016USD ($)MMBTUMWh | Dec. 31, 2015USD ($) | |
Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | |||
Purchase of Units Derivative Instruments Forward Power Contracts Designated as Cash Flow Hedge | MWh | 678,500 | 342,900 | |
Sales of Units Derivative Instruments Forward Power Contracts Designated as Cash Flow Hedge | MWh | (1,667,000) | (9,974,500) | |
Derivative, Nonmonetary Notional Amount MWh | MWh | (988,500) | (9,631,600) | |
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | |||
Sale of Derivative Instruments Interest Rate Swap | $ 0 | $ 0 | |
Purchase of Derivative Instruments Interest Rate Swap | 200,000,000 | 200,000,000 | |
Derivative, Notional Amount, Purchase (Sales), Net | 200,000,000 | 200,000,000 | |
Designated as Hedging Instrument [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Interest Rate Swap [Member] | |||
Derivative, Notional Amount, Purchase (Sales), Net | 200,000,000 | ||
Not Designated as Hedging Instrument [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 3,200,000 | (900,000) | $ (16,000,000) |
Not Designated as Hedging Instrument [Member] | Commodity Contract - FTR [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | $ 400,000 | $ (300,000) | 100,000 |
Purchase of Units Derivative Instruments Financial Transmission Rights | MWh | 2,100 | 2,300 | |
Sale of Units Derivative Instruments Financial Transmission Rights | MWh | 0 | 0 | |
Derivative, Nonmonetary Notional Amount MWh | MWh | 2,100 | 2,300 | |
Not Designated as Hedging Instrument [Member] | Commodity Contract - Heating Oil [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 100,000 | ||
Not Designated as Hedging Instrument [Member] | Natural Gas [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | $ 1,600,000 | $ 2,600,000 | 0 |
Purchase of Units Derivative Instruments Natural Gas | MMBTU | 3,322,500 | 1,590,000 | |
Sale of Units Derivative Instruments Natural Gas | MMBTU | (390,000) | 0 | |
Derivative, Nonmonetary Notional Amount MWh | MMBTU | 2,932,500 | 1,590,000 | |
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | $ 1,200,000 | $ (3,200,000) | (16,200,000) |
Purchase of Units Derivative Instruments Forward Power Contracts Not Designated as Hedged | MWh | 871,000 | 2,568,300 | |
Sales of Units Derivative Instruments Forward Power Contracts Not Designated as Hedged | MWh | (765,600) | (2,020,900) | |
Derivative, Nonmonetary Notional Amount MWh | MWh | 105,400 | 547,400 | |
Sales [Member] | Not Designated as Hedging Instrument [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | $ (1,200,000) | $ (17,300,000) | |
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] | 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 | (1,200,000) | (17,300,000) | |
Fuel [Member] | Not Designated as Hedging Instrument [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 27,400,000 | ||
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 | 0 | ||
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 | 27,400,000 | ||
Purchased Power [Member] | Not Designated as Hedging Instrument [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 4,400,000 | 16,400,000 | (43,500,000) |
Purchased Power [Member] | Not Designated as Hedging Instrument [Member] | Commodity Contract - FTR [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 400,000 | (300,000) | 100,000 |
Purchased Power [Member] | Not Designated as Hedging Instrument [Member] | Commodity Contract - Heating Oil [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | ||
Purchased Power [Member] | Not Designated as Hedging Instrument [Member] | Natural Gas [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 1,600,000 | 2,600,000 | 0 |
Purchased Power [Member] | Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | $ 2,400,000 | $ 14,100,000 | $ (43,600,000) |
Derivative Instruments and He66
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, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Forward Contract Power [Member] | |||
Beginning accumulated derivative gain / (loss) in AOCI | $ (4.3) | $ 9.2 | $ 0.2 |
Net gains / (losses) associated with current period hedging transactions | 8.8 | 15.7 | 18.2 |
Ending accumulated derivative gain / (loss) in AOCI | (2.8) | (4.3) | 9.2 |
Portion expected to be reclassified to earnings in the next twelve months | $ (2.7) | ||
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) | 3 months | ||
Interest Rate Contract [Member] | |||
Beginning accumulated derivative gain / (loss) in AOCI | $ 17.4 | 17.5 | 18.3 |
Net gains / (losses) associated with current period hedging transactions | 0.8 | 0.4 | 0 |
Ending accumulated derivative gain / (loss) in AOCI | 17.5 | 17.4 | 17.5 |
Portion expected to be reclassified to earnings in the next twelve months | $ (0.7) | ||
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) | 32 months | ||
THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member] | |||
Derivative Instrument, loss from discontinued operations | $ (5.5) | (29.2) | (9.2) |
Beginning accumulated derivative gain / (loss) in AOCI | (4.3) | 9.2 | 0.2 |
Net gains / (losses) associated with current period hedging transactions | 10.7 | 15.7 | 18.2 |
Ending accumulated derivative gain / (loss) in AOCI | (1.2) | (4.3) | 9.2 |
Derivative Instrument, transfer of generation assets of subsidiary | (2.1) | ||
THE DAYTON POWER AND LIGHT COMPANY [Member] | Interest Rate Contract [Member] | |||
Beginning accumulated derivative gain / (loss) in AOCI | 1.6 | 2 | 2.6 |
Net gains / (losses) associated with current period hedging transactions | 1.7 | 0.4 | 0 |
Ending accumulated derivative gain / (loss) in AOCI | 2.6 | 1.6 | 2 |
Portion expected to be reclassified to earnings in the next twelve months | $ (0.7) | ||
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) | 32 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 | (0.7) | (0.5) | (0.8) |
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 | (0.7) | (0.8) | (0.6) |
Sales [Member] | Forward Contract Power [Member] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | (9.8) | (35.6) | (12) |
Sales [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 | 2.5 | 6.4 | 2.8 |
Purchased Power [Member] | Interest Rate Contract [Member] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | $ 0 | $ 0 | $ 0 |
Derivative Instruments and He67
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, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Change in unrealized gain / (loss) | $ 1.6 | $ 4.3 | $ (5.6) |
Realized gain / (loss) | 1.6 | (5.2) | (10.4) |
Derivative, Gain (Loss) on Derivative, Net | 3.2 | (0.9) | (16) |
Commodity Contract - Heating Oil [Member] | |||
Change in unrealized gain / (loss) | 0.4 | ||
Realized gain / (loss) | (0.3) | ||
Derivative, Gain (Loss) on Derivative, Net | 0.1 | ||
Commodity Contract - FTR [Member] | |||
Change in unrealized gain / (loss) | (0.4) | 0.3 | 0.3 |
Realized gain / (loss) | 0.8 | (0.6) | (0.2) |
Derivative, Gain (Loss) on Derivative, Net | 0.4 | (0.3) | 0.1 |
Forward Contract Power [Member] | |||
Change in unrealized gain / (loss) | 1.9 | 4 | (6.4) |
Realized gain / (loss) | (0.7) | (7.2) | (9.8) |
Derivative, Gain (Loss) on Derivative, Net | 1.2 | (3.2) | (16.2) |
Natural Gas [Member] | |||
Change in unrealized gain / (loss) | 0.1 | 0 | 0.1 |
Realized gain / (loss) | 1.5 | 2.6 | (0.1) |
Derivative, Gain (Loss) on Derivative, Net | 1.6 | 2.6 | 0 |
Fuel [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 27.4 | ||
Fuel [Member] | Commodity Contract - Heating Oil [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | ||
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 | 27.4 | ||
Fuel [Member] | Natural Gas [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | ||
Purchased Power [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 4.4 | 16.4 | (43.5) |
Purchased Power [Member] | Commodity Contract - Heating Oil [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | ||
Purchased Power [Member] | Commodity Contract - FTR [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0.4 | (0.3) | 0.1 |
Purchased Power [Member] | Forward Contract Power [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 2.4 | 14.1 | (43.6) |
Purchased Power [Member] | Natural Gas [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 1.6 | 2.6 | 0 |
Regulatory Asset [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | 0.1 |
Regulatory Asset [Member] | Commodity Contract - Heating Oil [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 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 |
Derivative Instruments and He68
Derivative Instruments and Hedging Activities (Fair Value and Balance Sheet Location (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Derivative Liability, Fair Value | $ 15.3 | |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 1.4 | |
Total Assets [Member] | ||
Derivative Asset, Fair Value | 12.8 | $ 20.8 |
Derivative, Collateral, Obligation to Return Securities | (8.7) | (16.8) |
Derivative, Collateral, Obligation to Return Cash | 0 | 0 |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 4.1 | 4 |
Total Liabilities [Member] | ||
Derivative Liability, Fair Value | 15.3 | 29.2 |
Derivative, Collateral, Right to Reclaim Securities | (8.7) | (16.8) |
Derivative, Collateral, Right to Reclaim Cash | (1.4) | (6.3) |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 5.2 | 6.1 |
Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Prepayments and Current Assets [Member] | ||
Derivative Asset, Fair Value | 4.9 | 11 |
Derivative, Collateral, Obligation to Return Securities | (4.9) | (10.5) |
Derivative, Collateral, Obligation to Return Cash | 0 | 0 |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 0 | 0.5 |
Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member] | ||
Derivative Liability, Fair Value | 9 | 16.4 |
Derivative, Collateral, Right to Reclaim Securities | (4.9) | (10.5) |
Derivative, Collateral, Right to Reclaim Cash | (1.4) | (5.5) |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 2.7 | 0.4 |
Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Asset [Member] | ||
Derivative Asset, Fair Value | 0 | 0.6 |
Derivative, Collateral, Obligation to Return Securities | 0 | (0.6) |
Derivative, Collateral, Obligation to Return Cash | 0 | 0 |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 0 | 0 |
Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Credit [Member] | ||
Derivative Liability, Fair Value | 2.4 | |
Derivative, Collateral, Right to Reclaim Securities | (0.6) | |
Derivative, Collateral, Right to Reclaim Cash | (0.8) | |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 1 | |
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Other Deferred Asset [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Derivative Asset, Fair Value | 1.8 | 1.2 |
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Other Current Liabilities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Derivative Liability, Fair Value | 0 | 0.7 |
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] | Long-term Derivative Positions [Member] | Other Deferred Asset [Member] | ||
Derivative Asset, Fair Value | 1.8 | 1.2 |
Derivative, Collateral, Obligation to Return Securities | 0 | 0 |
Derivative, Collateral, Obligation to Return Cash | 0 | 0 |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 1.8 | 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 | 5.3 | 6 |
Derivative, Collateral, Obligation to Return Securities | (3.7) | (4.7) |
Derivative, Collateral, Obligation to Return Cash | 0 | 0 |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 1.6 | 1.3 |
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member] | ||
Derivative Liability, Fair Value | 5.9 | 7.7 |
Derivative, Collateral, Right to Reclaim Securities | (3.7) | (4.7) |
Derivative, Collateral, Right to Reclaim Cash | 0 | 0 |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 2.2 | 3 |
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Asset [Member] | ||
Derivative Asset, Fair Value | 0.6 | 1.9 |
Derivative, Collateral, Obligation to Return Securities | 0 | (1) |
Derivative, Collateral, Obligation to Return Cash | 0 | 0 |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 0.6 | 0.9 |
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Credit [Member] | ||
Derivative Liability, Fair Value | 2 | |
Derivative, Collateral, Right to Reclaim Securities | (1) | |
Derivative, Collateral, Right to Reclaim Cash | 0 | |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 1 | |
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 | 0.2 | 0.1 |
Derivative, Collateral, Obligation to Return Securities | (0.1) | 0 |
Derivative, Collateral, Obligation to Return Cash | 0 | 0 |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 0.1 | $ 0.1 |
Not Designated as Hedging Instrument [Member] | Commodity Contract - FTR [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member] | ||
Derivative Liability, Fair Value | 0.3 | |
Derivative, Collateral, Right to Reclaim Securities | 0 | |
Derivative, Collateral, Right to Reclaim Cash | 0 | |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 0.3 | |
Not Designated as Hedging Instrument [Member] | Natural Gas [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member] | ||
Derivative Liability, Fair Value | 0.1 | |
Derivative, Collateral, Right to Reclaim Securities | (0.1) | |
Derivative, Collateral, Right to Reclaim Cash | 0 | |
Derivative Liability, Fair Value, Amount Offset Against Collateral | $ 0 |
Goodwill And Other Intangible69
Goodwill And Other Intangible Assets (Change In Goodwill) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2015 | Mar. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Goodwill [Line Items] | |||||
Goodwill impairment | $ 0 | $ 0 | $ (317) | ||
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Goodwill [Line Items] | |||||
Goodwill impairment | $ (317) | $ (317) |
Goodwill And Other Intangible70
Goodwill And Other Intangible Asset (Narrative) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||
Dec. 31, 2015 | Mar. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | |
Goodwill [Line Items] | ||||||
Goodwill, Impairment Loss | $ 0 | $ 0 | $ 317 | |||
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||||
Goodwill [Line Items] | ||||||
Goodwill | $ 317 | |||||
Goodwill, Impairment Loss | $ 317 | $ 317 |
Debt (Narrative) (Details)
Debt (Narrative) (Details) | Dec. 31, 2017USD ($) | Dec. 08, 2017USD ($) | Oct. 30, 2017USD ($) | Sep. 30, 2017 | Aug. 07, 2017USD ($) | Jul. 01, 2017 | Jun. 23, 2017USD ($) | Oct. 17, 2016USD ($) | Feb. 05, 2016USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2019 | Jun. 30, 2019 | Dec. 31, 2018USD ($) | Jul. 03, 2018USD ($) | Sep. 30, 2017 | Dec. 31, 2020 | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Jan. 03, 2018 | Dec. 31, 2017USD ($) | Dec. 31, 2017fiscal_quarter | Dec. 31, 2017debt_covenant | Mar. 31, 2017 | Dec. 31, 2016USD ($) | Jan. 06, 2016USD ($) | Sep. 30, 2015fiscal_quarter | Aug. 03, 2015USD ($) |
Debt Instrument [Line Items] | |||||||||||||||||||||||||||
Current portion - long-term debt | $ 4,700,000 | ||||||||||||||||||||||||||
Unamortized adjustments to market value from purchase accounting | 2,500,000 | ||||||||||||||||||||||||||
Unamortized Deferred Financing Costs | (6,800,000) | $ (8,800,000) | |||||||||||||||||||||||||
Current portion - long-term debt | 4,700,000 | 29,700,000 | |||||||||||||||||||||||||
Repayments of debt | $ 70,000,000 | ||||||||||||||||||||||||||
Non-recurring cash expenses | $ 25,000,000 | ||||||||||||||||||||||||||
Required repayment or refinance | $ 100,000,000 | ||||||||||||||||||||||||||
Debt Covenant, Leverage Ratio, Maximum | 0.67 | ||||||||||||||||||||||||||
Debt Covenant, Interest Coverage Ratio, Minimum | 2.50 | ||||||||||||||||||||||||||
Leverage Ratio | 1.50 | ||||||||||||||||||||||||||
Debt Covenant, Total Debt to Total Capitalization Ratio, Maximum | 0.75 | 0.65 | |||||||||||||||||||||||||
Long Term Indebtedness, Less than or Equal to | $ 750,000,000 | ||||||||||||||||||||||||||
Total Debt to Total Capitalization Ratio | 0.67 | 0.61 | 0.75 | 0.65 | |||||||||||||||||||||||
Capital Lease Obligations | 200,000 | 400,000 | |||||||||||||||||||||||||
Debt Instrument, Unamortized Discount (Premium), Net | 500,000 | 600,000 | |||||||||||||||||||||||||
Total Long-term Debt At Subsidiary With Purchase Accounting Adjustments | 646,800,000 | 747,200,000 | |||||||||||||||||||||||||
Long-term Debt, Excluding Current Maturities | 1,700,400,000 | 1,828,700,000 | |||||||||||||||||||||||||
Long-term Debt, Maturities, Repayments of Principal in Year Two | 224,500,000 | ||||||||||||||||||||||||||
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||
Current portion - long-term debt | 4,600,000 | ||||||||||||||||||||||||||
Unamortized Deferred Financing Costs | (9,800,000) | (11,700,000) | |||||||||||||||||||||||||
Current portion - long-term debt | 4,600,000 | 4,600,000 | |||||||||||||||||||||||||
Repayments of debt | $ 70,000,000 | ||||||||||||||||||||||||||
Debt Covenant, Total Debt to Total Capitalization Ratio, Maximum | 0.75 | 0.65 | |||||||||||||||||||||||||
Long Term Indebtedness, Less than or Equal to | $ 750,000,000 | $ 750,000,000 | |||||||||||||||||||||||||
Total Debt to Total Capitalization Ratio | 0.67 | 0.61 | 0.75 | 0.65 | |||||||||||||||||||||||
Capital Lease Obligations | 0 | 400,000 | |||||||||||||||||||||||||
Unamortized Deferred Financing Costs (Subsidiary) | (9,800,000) | (10,700,000) | |||||||||||||||||||||||||
Debt Instrument, Unamortized Discount (Premium), Net | 2,000,000 | 5,500,000 | |||||||||||||||||||||||||
Long-term Debt, Excluding Current Maturities | 642,000,000 | 731,500,000 | |||||||||||||||||||||||||
Long-term Debt, Maturities, Repayments of Principal in Year Two | 4,600,000 | ||||||||||||||||||||||||||
Term Loan Maturing 2022 (DPL) [Member] | |||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||
Debt Instrument, Maturity Date Range, End | Aug. 24, 2022 | ||||||||||||||||||||||||||
Long-term Debt, Gross | 440,600,000 | 445,000,000 | |||||||||||||||||||||||||
Term Loan Maturing 2022 (DPL) [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||
Debt Instrument, Maturity Date Range, End | Aug. 24, 2022 | ||||||||||||||||||||||||||
Long-term Debt, Gross | 440,600,000 | 445,000,000 | |||||||||||||||||||||||||
Eurodollar rate Term Loan B [Member] | |||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||
Debt instrument interest percentage | 3.25% | 3.25% | 3.25% | ||||||||||||||||||||||||
Eurodollar rate Term Loan B [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||
Debt instrument interest percentage | 3.25% | 3.25% | 3.25% | ||||||||||||||||||||||||
Base Rate Term Loan B [Member] | |||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||
Debt instrument interest percentage | 2.25% | 2.25% | 2.25% | ||||||||||||||||||||||||
Base Rate Term Loan B [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||
Debt instrument interest percentage | 2.25% | 2.25% | 2.25% | ||||||||||||||||||||||||
Revolving Credit Agreement and Standby Letters of Credit [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||
Number of financial covenants | 2 | 2 | 2 | 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 | 17,800,000 | 18,000,000 | |||||||||||||||||||||||||
Debt instrument interest percentage | 4.20% | 4.20% | 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 | 17,800,000 | $ 18,000,000 | |||||||||||||||||||||||||
Debt instrument interest percentage | 4.20% | 4.20% | 4.20% | ||||||||||||||||||||||||
First Mortgage Bonds Maturing in 2016 - 1.875% | |||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||
Debt instrument interest percentage | 1.875% | ||||||||||||||||||||||||||
First Mortgage Bonds Maturing in 2016 - 1.875% | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||
Debt instrument interest percentage | 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% | ||||||||||||||||||||||||||
Quarterly Loan Amortization of Initial Principal Balance | 0.25% | ||||||||||||||||||||||||||
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% | ||||||||||||||||||||||||||
Quarterly Loan Amortization of Initial Principal Balance | 0.25% | ||||||||||||||||||||||||||
Bank Term Loan maturing in May 2018 [Member] | |||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||
Debt Instrument, Maturity Date Range, End | Jul. 31, 2020 | ||||||||||||||||||||||||||
Bank Term Loan Maturing July 2020 [Member] | |||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||
Long-term Debt, Gross | 70,000,000 | $ 125,000,000 | |||||||||||||||||||||||||
Extinguishment of debt, amount | $ 30,000,000 | ||||||||||||||||||||||||||
Five Year Senior Unsecured Notes At6.75 Maturing October152019 [Member] | |||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||
Debt Instrument, Maturity Date Range, End | Oct. 1, 2019 | ||||||||||||||||||||||||||
Long-term Debt, Gross | 200,000,000 | 200,000,000 | |||||||||||||||||||||||||
Debt instrument interest percentage | 6.75% | 6.75% | 6.75% | ||||||||||||||||||||||||
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] | |||||||||||||||||||||||||||
Long-term Debt, Gross | $ 130,000,000 | ||||||||||||||||||||||||||
Make Whole Premium | $ 2,400,000 | ||||||||||||||||||||||||||
Extinguishment of debt, amount | $ 57,000,000 | $ 73,000,000 | |||||||||||||||||||||||||
Debt instrument interest percentage | 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% | 7.25% | 7.25% | ||||||||||||||||||||||||
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 | |||||||||||||||||||||||||
Debt instrument interest percentage | 8.125% | 8.125% | 8.125% | ||||||||||||||||||||||||
Note Payable to DPL Inc. [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||
Debt instrument interest percentage | 3.02% | ||||||||||||||||||||||||||
Notes payable - related party | $ 5,000,000 | ||||||||||||||||||||||||||
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 | ||||||||||||||||||||||||||
Pollution Control Series Maturing in 2036 - 4.80% [Member] | |||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||
Debt Instrument, Maturity Date Range, End | Sep. 1, 2036 | ||||||||||||||||||||||||||
Long-term Debt, Gross | 0 | 100,000,000 | |||||||||||||||||||||||||
Extinguishment of debt, amount | $ 21,900,000 | $ 8,100,000 | |||||||||||||||||||||||||
Debt instrument interest percentage | 4.80% | 4.80% | 4.80% | ||||||||||||||||||||||||
Pollution Control Series Maturing in 2036 - 4.80% [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||
Debt Instrument, Maturity Date Range, End | Sep. 1, 2036 | ||||||||||||||||||||||||||
Long-term Debt, Gross | 0 | 100,000,000 | |||||||||||||||||||||||||
Extinguishment of debt, amount | $ 21,900,000 | $ 8,100,000 | |||||||||||||||||||||||||
Debt instrument interest percentage | 4.80% | 4.80% | 4.80% | ||||||||||||||||||||||||
One Point One Three To One Point One Seven Bonds Maturing In August Two Thousand Twenty [Member] | |||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||
Debt Instrument, Maturity Date Range, End | Aug. 1, 2020 | ||||||||||||||||||||||||||
Long-term Debt, Gross | 200,000,000 | 200,000,000 | |||||||||||||||||||||||||
One Point One Three To One Point One Seven Bonds Maturing In August Two Thousand Twenty [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||
Debt Instrument, Maturity Date Range, End | Aug. 1, 2020 | ||||||||||||||||||||||||||
Long-term Debt, Gross | 200,000,000 | 200,000,000 | |||||||||||||||||||||||||
Subsequent Event [Member] | |||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||
Debt Covenant, Leverage Ratio, Maximum | 6.75 | 7 | 6.50 | 7.25 | |||||||||||||||||||||||
Long Term Indebtedness, Less than or Equal to | $ 750,000,000 | ||||||||||||||||||||||||||
Subsequent Event [Member] | Eurodollar rate Term Loan B [Member] | |||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||
Debt instrument interest percentage | 2.00% | ||||||||||||||||||||||||||
Subsequent Event [Member] | Eurodollar rate Term Loan B [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||
Debt instrument interest percentage | 2.00% | ||||||||||||||||||||||||||
Subsequent Event [Member] | Base Rate Term Loan B [Member] | |||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||
Debt instrument interest percentage | 1.00% | ||||||||||||||||||||||||||
Subsequent Event [Member] | Base Rate Term Loan B [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||
Debt instrument interest percentage | 1.00% | ||||||||||||||||||||||||||
Subsequent Event [Member] | Term Loan Maturing 2022 [Member] | |||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||
Early prepayment rate | $ 1.01 | ||||||||||||||||||||||||||
Standard Repayment Rate | $ 1 | ||||||||||||||||||||||||||
Subsequent Event [Member] | Term Loan Maturing 2022 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||
Early prepayment rate | $ 1.01 | ||||||||||||||||||||||||||
Standard Repayment Rate | $ 1 | ||||||||||||||||||||||||||
Debt [Member] | |||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||
Long-term Debt and Capital Lease Obligations, Including Current Maturities | 1,705,100,000 | 1,858,400,000 | |||||||||||||||||||||||||
Debt [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||
Long-term Debt and Capital Lease Obligations, Including Current Maturities | $ 646,600,000 | $ 736,100,000 |
Debt (Long-term Debt) (Details)
Debt (Long-term Debt) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2017 | Oct. 01, 2017 | Dec. 31, 2016 | Jan. 06, 2016 | |
Debt Instrument [Line Items] | ||||
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months | $ 4.7 | |||
Capital Lease Obligations | 0.2 | $ 0.4 | ||
Unamortized Deferred Financing Costs | (6.8) | (8.8) | ||
Debt Instrument, Unamortized Discount (Premium), Net | (0.5) | (0.6) | ||
Total long-term debt at subsidary | 646.8 | 747.2 | ||
Less: current portion | (4.7) | (29.7) | ||
Long-term debt, net of current portion | $ 1,700.4 | 1,828.7 | ||
Debt maturity date, earliest | 2,019 | |||
Debt maturity date, latest | 2,061 | |||
Long-term Debt, Maturities, Repayments of Principal in Year Two | $ 224.5 | |||
Long-term Debt, Maturities, Repayments of Principal in Year Three | 254.6 | |||
Long-term Debt, Maturities, Repayments of Principal in Year Four | 784.6 | |||
Long-term Debt, Maturities, Repayments of Principal in Year Five | 422.9 | |||
Long-term Debt, Maturities, Repayments of Principal after Year Five | 32.7 | |||
Total Maturities Before Unamortized Adjustments | 1,724 | |||
Unamortized adjustments to market value from purchase accounting | 2.5 | |||
Long Term Debt Maturities Repayments Of Principal, Total | 1,721.5 | |||
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Debt Instrument [Line Items] | ||||
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months | 4.6 | |||
Capital Lease Obligations | 0 | 0.4 | ||
Unamortized Deferred Financing Costs | (9.8) | (11.7) | ||
Unamortized Deferred Financing Costs (Subsidiary) | (9.8) | (10.7) | ||
Debt Instrument, Unamortized Discount | (2) | (2.2) | ||
Debt Instrument, Unamortized Discount (Premium), Net | (2) | (5.5) | ||
Less: current portion | (4.6) | (4.6) | ||
Long-term debt, net of current portion | 642 | 731.5 | ||
Long-term Debt, Maturities, Repayments of Principal in Year Two | 4.6 | |||
Long-term Debt, Maturities, Repayments of Principal in Year Three | 204.6 | |||
Long-term Debt, Maturities, Repayments of Principal in Year Four | 4.6 | |||
Long-term Debt, Maturities, Repayments of Principal in Year Five | 422.9 | |||
Long-term Debt, Maturities, Repayments of Principal after Year Five | 17.1 | |||
Total Maturities Before Unamortized Adjustments | 658.4 | |||
Long Term Debt Maturities Repayments Of Principal, Total | 656.4 | |||
Term Loan Maturing 2022 (DPL) [Member] | ||||
Debt Instrument [Line Items] | ||||
Long-term Debt, Gross | $ 440.6 | 445 | ||
Debt instrument maturity year | Aug. 24, 2022 | |||
Term Loan Maturing 2022 (DPL) [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Debt Instrument [Line Items] | ||||
Long-term Debt, Gross | $ 440.6 | $ 445 | ||
Debt instrument maturity year | Aug. 24, 2022 | |||
First Mortgage Bonds Maturing in 2016 - 1.875% | ||||
Debt Instrument [Line Items] | ||||
Debt instrument interest percentage | 1.875% | |||
First Mortgage Bonds Maturing in 2016 - 1.875% | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt instrument interest percentage | 1.875% | |||
Pollution Control Series Maturing in 2036 - 4.80% [Member] | ||||
Debt Instrument [Line Items] | ||||
Long-term Debt, Gross | $ 0 | $ 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 | $ 0 | 100 | ||
Debt instrument maturity year | Sep. 1, 2036 | |||
Debt instrument interest percentage | 4.80% | |||
Tax-exempt First Mortgage Bonds - rates from: 1.52% - 1.92% (a) and 1.29% - 1.42% (b) | ||||
Debt Instrument [Line Items] | ||||
Long-term Debt, Gross | $ 200 | 200 | ||
Debt instrument maturity year | Aug. 1, 2020 | |||
Tax-exempt First Mortgage Bonds - rates from: 1.52% - 1.92% (a) and 1.29% - 1.42% (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 | |||
U.S. Government note maturing in 2061 - 4.20% [Member] | ||||
Debt Instrument [Line Items] | ||||
Long-term Debt, Gross | $ 17.8 | 18 | ||
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 | $ 17.8 | 18 | ||
Debt instrument maturity year | Feb. 1, 2061 | |||
Debt instrument interest percentage | 4.20% | |||
Bank Term Loan Maturing July 2020 [Member] | ||||
Debt Instrument [Line Items] | ||||
Long-term Debt, Gross | $ 70 | 125 | ||
Bank Term Loan maturing in May 2018 [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt instrument maturity year | Jul. 31, 2020 | |||
Senior Unsecured Bonds at 6.50% maturing in 2016 [Member] | ||||
Debt Instrument [Line Items] | ||||
Long-term Debt, Gross | $ 130 | |||
Debt instrument interest percentage | 6.50% | |||
Five Year Senior Unsecured Notes At6.75 Maturing October152019 [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% | |||
Minimum [Member] | Term Loan Maturing 2022 (DPL) [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt Instrument, Interest Rate, Effective Percentage Rate Range, Minimum (Deprecated 2016-01-31) | 4.00% | 4.00% | ||
Minimum [Member] | Term Loan Maturing 2022 (DPL) [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt Instrument, Interest Rate, Effective Percentage Rate Range, Minimum (Deprecated 2016-01-31) | 4.00% | 4.00% | ||
Minimum [Member] | Tax-exempt First Mortgage Bonds - rates from: 1.52% - 1.92% (a) and 1.29% - 1.42% (b) | ||||
Debt Instrument [Line Items] | ||||
Debt instrument interest percentage | 1.52% | 1.29% | ||
Minimum [Member] | Tax-exempt First Mortgage Bonds - rates from: 1.52% - 1.92% (a) and 1.29% - 1.42% (b) | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt instrument interest percentage | 1.52% | |||
Minimum [Member] | Bank Term Loan maturing in May 2018 [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt instrument interest percentage | 3.02% | 2.67% | ||
Maximum [Member] | Term Loan Maturing 2022 (DPL) [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt Instrument, Interest Rate, Effective Percentage Rate Range, Minimum (Deprecated 2016-01-31) | 4.60% | 4.00% | ||
Maximum [Member] | Term Loan Maturing 2022 (DPL) [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt Instrument, Interest Rate, Effective Percentage Rate Range, Minimum (Deprecated 2016-01-31) | 4.60% | 4.00% | ||
Maximum [Member] | Tax-exempt First Mortgage Bonds - rates from: 1.52% - 1.92% (a) and 1.29% - 1.42% (b) | ||||
Debt Instrument [Line Items] | ||||
Debt instrument interest percentage | 1.92% | 1.42% | ||
Maximum [Member] | Tax-exempt First Mortgage Bonds - rates from: 1.52% - 1.92% (a) and 1.29% - 1.42% (b) | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt instrument interest percentage | 1.92% | |||
Maximum [Member] | Bank Term Loan maturing in May 2018 [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt instrument interest percentage | 4.10% | 3.02% | ||
Debt [Member] | ||||
Debt Instrument [Line Items] | ||||
Long-term Debt and Capital Lease Obligations, Including Current Maturities | $ 1,705.1 | $ 1,858.4 | ||
Debt [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Debt Instrument [Line Items] | ||||
Long-term Debt and Capital Lease Obligations, Including Current Maturities | $ 646.6 | 736.1 | ||
Generation [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Debt Instrument [Line Items] | ||||
Disposal Group, Including Discontinued Operations, Long-Term Debt | $ (0.3) | $ (13.4) |
Debt (Long-term Debt Maturities
Debt (Long-term Debt Maturities) (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Oct. 01, 2017 | Dec. 31, 2016 |
Debt Instrument [Line Items] | |||
Current portion - long-term debt | $ 4.7 | ||
Long-term Debt, Maturities, Repayments of Principal in Year Two | 224.5 | ||
2,018 | 254.6 | ||
2,019 | 784.6 | ||
2,020 | 422.9 | ||
Thereafter | 32.7 | ||
Total Maturities | 1,724 | ||
Total long-term debt | 1,721.5 | ||
Capital Lease Obligations | 0.2 | $ 0.4 | |
Unamortized Deferred Financing Costs | (6.8) | (8.8) | |
Current portion - long-term debt | 4.7 | 29.7 | |
Long-term Debt, Excluding Current Maturities | 1,700.4 | 1,828.7 | |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Debt Instrument [Line Items] | |||
Current portion - long-term debt | 4.6 | ||
Long-term Debt, Maturities, Repayments of Principal in Year Two | 4.6 | ||
2,018 | 204.6 | ||
2,019 | 4.6 | ||
2,020 | 422.9 | ||
Thereafter | 17.1 | ||
Total Maturities | 658.4 | ||
Debt Instrument, Unamortized Discount | (2) | (2.2) | |
Total long-term debt | 656.4 | ||
Capital Lease Obligations | 0 | 0.4 | |
Unamortized Deferred Financing Costs | (9.8) | (11.7) | |
Current portion - long-term debt | 4.6 | 4.6 | |
Long-term Debt, Excluding Current Maturities | 642 | 731.5 | |
Term Loan Maturing 2022 (DPL) [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Gross | 440.6 | 445 | |
Term Loan Maturing 2022 (DPL) [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Gross | 440.6 | 445 | |
Pollution Control Series Maturing in 2036 - 4.80% [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Gross | 0 | 100 | |
Pollution Control Series Maturing in 2036 - 4.80% [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Gross | 0 | 100 | |
One Point One Three To One Point One Seven Bonds Maturing In August Two Thousand Twenty [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Gross | 200 | 200 | |
One Point One Three To One Point One Seven Bonds Maturing In August Two Thousand Twenty [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Gross | 200 | 200 | |
Four Point Two Zero Percentage Of U S Government Note Maturing In February Two Thousand Sixty One [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Gross | 17.8 | 18 | |
Four Point Two Zero Percentage Of U S Government Note Maturing In February Two Thousand Sixty One [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Gross | 17.8 | 18 | |
Generation [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Debt Instrument [Line Items] | |||
Disposal Group, Including Discontinued Operations, Long-Term Debt | $ 0.3 | 13.4 | |
Debt [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt and Capital Lease Obligations, Including Current Maturities | 1,705.1 | 1,858.4 | |
Debt [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt and Capital Lease Obligations, Including Current Maturities | $ 646.6 | $ 736.1 |
Income Taxes (Components of Inc
Income Taxes (Components of Income Tax Expense) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Income Taxes [Line Items] | |||
Estimated Annual Effective Income Tax Rate, Continuing Operations | 35.00% | ||
Federal income tax | $ (42) | $ (277.6) | $ (81) |
State income taxes, net of federal effect | (0.5) | (1) | (0.1) |
Depreciation of AFUDC - Equity | 0.8 | 2.7 | (3.5) |
Investment tax credit amortized | (0.3) | (0.4) | (0.5) |
Section 199 - domestic production deduction | 0 | (4.5) | (4.1) |
Non-deductible goodwill impairment | 0 | 0 | 111 |
Accrual (settlement) for open tax years | (0.4) | 2.2 | 0 |
Other, net | 17.1 | (0.2) | (1.8) |
Tax expense / (benefit) | (25.3) | (278.8) | 20 |
Federal - Current | (2.9) | 14.7 | 30.1 |
State and Local - Current | 0 | 0.6 | 0.8 |
Total Current | (2.9) | 15.3 | 30.9 |
Federal - Deferred | (22) | (290.2) | (9.9) |
State and Local - Deferred | (0.4) | (3.9) | (1) |
Total Deferred | (22.4) | (294.1) | (10.9) |
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense | $ 3.5 | (0.3) | 0.2 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Income Taxes [Line Items] | |||
Estimated Annual Effective Income Tax Rate, Continuing Operations | 35.00% | ||
Federal income tax | $ 31 | 50.1 | 65.8 |
State income taxes, net of federal effect | 0.4 | 0.4 | 0.4 |
Depreciation of AFUDC - Equity | 1.2 | 3 | (3.1) |
Investment tax credit amortized | (0.3) | (0.4) | (0.4) |
Accrual (settlement) for open tax years | (0.5) | 3.4 | 0 |
Other, net | (0.7) | (10.5) | (3.7) |
Tax expense / (benefit) | 31.1 | 46 | 59 |
Federal - Current | 13.5 | 37.7 | 68.3 |
State and Local - Current | 0.2 | 0.5 | 0.9 |
Total Current | 13.7 | 38.2 | 69.2 |
Federal - Deferred | 17 | 7.7 | (9.9) |
State and Local - Deferred | 0.4 | 0.1 | (0.3) |
Total Deferred | 17.4 | 7.8 | (10.2) |
Increase (Decrease) in Income Taxes | $ 0 | $ (0.4) | $ (0.1) |
Income Taxes (Effective and Sta
Income Taxes (Effective and Statutory Rate Reconciliation) (Details) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Entity Information [Line Items] | |||
Statutory Federal tax rate | 35.00% | 35.00% | 35.00% |
State taxes, net of Federal tax benefit | 0.40% | 0.10% | 0.10% |
AFUDC - Equity | (0.70%) | (0.30%) | 1.50% |
Amortization of investment tax credits | 0.30% | 0.00% | 0.20% |
Section 199 - domestic production deduction | 0.00% | 0.60% | 1.80% |
Non-deductible goodwill impairment | 0.00% | 0.00% | (48.00%) |
Other, net (a) | (13.90%) | (0.30%) | 0.80% |
Effective tax rate | 21.10% | 35.10% | (8.60%) |
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% | 0.20% |
AFUDC - Equity | 1.40% | 2.10% | (1.70%) |
Amortization of investment tax credits | (0.40%) | (0.30%) | (0.20%) |
Other, net (a) | (1.30%) | (5.10%) | (2.10%) |
Effective tax rate | 35.10% | 32.00% | 31.20% |
Income Taxes (Components of Def
Income Taxes (Components of Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Income Taxes [Line Items] | |||
Depreciation / property basis | $ (103.6) | $ (234.8) | |
Income taxes recoverable | 11 | (11.9) | |
Regulatory assets | (23.1) | (7.8) | |
Investment tax credit | 0.5 | 0.5 | |
Compensation and employee benefits | 11.3 | 5.5 | |
Intangibles | (0.4) | (1.5) | |
Long-term debt | (0.2) | (0.7) | |
Other | (6.7) | (1.7) | |
Net non-current liabilities | $ (111.2) | (252.4) | |
Estimated Annual Effective Income Tax Rate, Continuing Operations | 35.00% | ||
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense | $ 3.5 | (0.3) | $ 0.2 |
Deferred tax assets related to state and local tax net operating loss carryforwards, net of related valuation allowances | 36.3 | 38.3 | |
Deferred tax assets related to state and local net operating loss carryforwards, valuation allowances | 36.3 | 38.3 | |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Income Taxes [Line Items] | |||
Depreciation / property basis | (126.5) | (238) | |
Income taxes recoverable | 11 | (12.2) | |
Regulatory assets | (23.9) | (9.1) | |
Investment tax credit | 0.4 | 0.4 | |
Compensation and employee benefits | 17.6 | (0.3) | |
Other | (9.6) | (7.7) | |
Net non-current liabilities | $ (131) | (266.9) | |
Estimated Annual Effective Income Tax Rate, Continuing Operations | 35.00% | ||
Increase (Decrease) in Income Taxes | $ 0 | $ (0.4) | $ (0.1) |
Income Taxes (Tax or Benefit cr
Income Taxes (Tax or Benefit credited to AOCI) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Income Taxes [Line Items] | |||
Tax expense/ (benefit) | $ 0.2 | $ (9.6) | $ 6.3 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Income Taxes [Line Items] | |||
Tax expense/ (benefit) | $ 4 | $ (7) | $ 7.5 |
Income Taxes (Reconciliation of
Income Taxes (Reconciliation of Unrecognized Tax Benefits) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | ||
Balance at beginning of year | $ 3.7 | $ 3 |
Tax positions taken during prior periods | 0 | 2.2 |
Lapse of applicable statute of limitations | (0.2) | (1.5) |
Balance at end of year | 3.5 | 3.7 |
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 | 4.9 | 3 |
Tax positions taken during prior periods | 0 | 3.4 |
Lapse of applicable statute of limitations | (0.1) | (1.5) |
Balance at end of year | $ 4.8 | $ 4.9 |
Income Taxes (Narrative) (Detai
Income Taxes (Narrative) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Income Taxes [Line Items] | ||||
Tax Cuts and Jobs Act of 2017, change in income tax expense (benefit) | $ 13.7 | |||
Tax rate before change due to Tax Cuts and Jobs Act of 2017 | 35.00% | |||
Non-cash capital contribution | $ 97.1 | $ 0 | $ 0 | |
Change in deferred tax regulatory asset/liability due to TCJA | 135.2 | |||
Unrecognized tax benefits due to uncertainty in timing of deductibility | $ 0.9 | |||
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Income Taxes [Line Items] | ||||
Tax rate before change due to Tax Cuts and Jobs Act of 2017 | 35.00% | |||
Change in deferred tax regulatory asset/liability due to TCJA | $ 135.2 | |||
Unrecognized tax benefits due to uncertainty in timing of deductibility | $ 0.9 | |||
Scenario, Forecast [Member] | ||||
Income Taxes [Line Items] | ||||
Tax rate after Tax Cuts and Jobs Act of 2017 | 21.00% | |||
Scenario, Forecast [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Income Taxes [Line Items] | ||||
Tax rate after Tax Cuts and Jobs Act of 2017 | 21.00% |
Benefit Plans (Narrative) (Deta
Benefit Plans (Narrative) (Details) - USD ($) | Jan. 31, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Amount Billed to Service Company | $ 1,100,000 | $ 1,300,000 | |||
Defined contribution plan, maximum annual contributions per employee (percent) | 85.00% | ||||
Employer contributions to defined contribution plan | $ 3,100,000 | 5,100,000 | $ 4,900,000 | ||
Accumulated benefit obligation for our defined benefit pension plans | 428,300,000 | 409,200,000 | |||
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Amount Billed to Service Company | $ 1,100,000 | 1,300,000 | |||
Defined contribution plan, maximum annual contributions per employee (percent) | 85.00% | ||||
Employer contributions to defined contribution plan | $ 3,100,000 | 5,100,000 | 4,900,000 | ||
Accumulated benefit obligation for our defined benefit pension plans | 428,300,000 | 409,200,000 | |||
Defined Benefit Plan, Amount Billed to AES Ohio Generation | $ 700,000 | ||||
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% | ||||
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% | ||||
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% | ||||
Pension [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Payment for Pension Benefits | $ 5,000,000 | $ 5,000,000 | $ 5,000,000 | ||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets | 6.50% | 6.50% | 6.50% | ||
Discount rate for obligations | 3.66% | 4.28% | 4.49% | ||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 4.28% | 4.49% | 4.02% | ||
Defined Benefit Plan, Fair Value of Plan Assets | $ 357,500,000 | $ 341,000,000 | $ 345,400,000 | ||
Service cost | 5,700,000 | 5,700,000 | 7,100,000 | ||
Interest cost | 14,200,000 | 14,700,000 | 17,300,000 | ||
Defined Benefit Plan, Funded (Unfunded) Status of Plan | $ (79,400,000) | (78,600,000) | |||
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] | |||||
Payment for Pension Benefits | $ 5,000,000 | $ 5,000,000 | $ 5,000,000 | ||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets | 6.50% | 6.50% | 6.50% | ||
Discount rate for obligations | 3.66% | 4.28% | 4.49% | ||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 4.28% | 4.49% | 4.02% | ||
Defined Benefit Plan, Fair Value of Plan Assets | $ 357,500,000 | $ 341,000,000 | $ 345,400,000 | ||
Service cost | 5,700,000 | 5,700,000 | 7,100,000 | ||
Interest cost | 14,200,000 | 14,700,000 | $ 17,300,000 | ||
Defined Benefit Plan, Funded (Unfunded) Status of Plan | $ (79,400,000) | (78,600,000) | |||
Defined benefit plan, amortization period for underfunding excess | 7 years | ||||
Postretirement [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Funded (Unfunded) Status of Plan | $ 12,700,000 | 15,800,000 | |||
Postretirement [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Funded (Unfunded) Status of Plan | $ 12,700,000 | $ 15,800,000 | |||
Equity Securities [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 38.00% | ||||
Equity Securities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 38.00% | ||||
Scenario, Forecast [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Increase in pension cost due to change in return on assets | $ 3,400,000 | ||||
Decrease in pension cost due to change in return on assets | (3,400,000) | ||||
Decrease in pension cost due to change in discount rate | (600,000) | ||||
Increase in pension cost due to change in discount rate | 600,000 | ||||
Scenario, Forecast [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Increase in pension cost due to change in return on assets | 3,400,000 | ||||
Decrease in pension cost due to change in return on assets | (3,400,000) | ||||
Decrease in pension cost due to change in discount rate | (600,000) | ||||
Increase in pension cost due to change in discount rate | 600,000 | ||||
Scenario, Forecast [Member] | Pension [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Service cost | 7,500,000 | ||||
Defined Benefit Plan, Plan Assets, Administration Expense | 2,200,000 | ||||
Scenario, Forecast [Member] | Pension [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Service cost | 7,500,000 | ||||
Defined Benefit Plan, Plan Assets, Administration Expense | $ 2,200,000 | ||||
Scenario, Forecast [Member] | SERP [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Target Allocation Percentage | 99.00% | ||||
Estimated contribution to the defined benefit plans next year | $ 400,000 | ||||
Scenario, Forecast [Member] | SERP [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Target Allocation Percentage | 99.00% | ||||
Estimated contribution to the defined benefit plans next year | $ 400,000 | ||||
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 | $ 2,300 | ||||
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 | $ 2,300 | ||||
Subsequent Event [Member] | Pension [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Payment for Pension Benefits | $ 7,500,000 | ||||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets | 6.25% | ||||
Subsequent Event [Member] | Pension [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Payment for Pension Benefits | $ 7,500,000 | ||||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets | 6.25% | ||||
Subsequent Event [Member] | Increase in Expected Rate of Return [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Change in Expected rate of return on plan assets | 1.00% | ||||
Subsequent Event [Member] | 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% | ||||
Subsequent Event [Member] | 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% | ||||
Subsequent Event [Member] | Expected Increase in Discount Rate [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Change in discount rate for plan assets | 25.00% | ||||
Subsequent Event [Member] | Expected Increase in Discount Rate [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Change in discount rate for plan assets | 25.00% | ||||
Subsequent Event [Member] | Expected Decrease in Discount Rate [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Change in discount rate for plan assets | 25.00% | ||||
Subsequent Event [Member] | Expected Decrease in Discount Rate [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Change in discount rate for plan assets | 25.00% | ||||
Minimum [Member] | Equity Securities [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 24.00% | ||||
Minimum [Member] | Equity Securities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 24.00% | ||||
Minimum [Member] | Fixed Income Securities [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 47.00% | ||||
Minimum [Member] | Fixed Income Securities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 47.00% | ||||
Maximum [Member] | Equity Securities [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 52.00% | ||||
Maximum [Member] | Equity Securities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 52.00% | ||||
Maximum [Member] | Fixed Income Securities [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 65.00% | ||||
Maximum [Member] | Fixed Income Securities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 65.00% |
Benefit Plans (Pension and Post
Benefit Plans (Pension and Postretirement Benefit Plans' Obligations and Assets) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Noncurrent liabilities | $ (101) | $ (101.6) | |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Noncurrent liabilities | (91.1) | (93.4) | |
Postretirement [Member] | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Defined Benefit Plan, Funded (Unfunded) Status of Plan | 12.7 | 15.8 | |
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 (Unfunded) Status of Plan | 12.7 | 15.8 | |
Pension [Member] | |||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | |||
Benefit obligation at January 1 | 419.6 | 410.8 | |
Service cost | 5.7 | 5.7 | $ 7.1 |
Interest cost | 14.2 | 14.7 | 17.3 |
Defined Benefit Plan, Benefit Obligation, (Increase) Decrease for Curtailment | 3 | 2.5 | |
Actuarial (gain) / loss | 28.1 | 9 | |
Benefit obligation at December 31 | 436.9 | 419.6 | 410.8 |
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value of plan assets at January 1 | 341 | 345.4 | |
Actual return / (loss) on plan assets | 44.8 | 13.3 | |
Contributions to plan assets | 5.4 | 5.4 | |
Fair value of plan assets at December 31 | 357.5 | 341 | 345.4 |
Defined Benefit Plan, Funded (Unfunded) Status of Plan | (79.4) | (78.6) | |
Current liabilities | (0.4) | (0.4) | |
Noncurrent liabilities | (79) | (78.2) | |
Net asset / (liability) at December 31 | (79.4) | (78.6) | |
Prior service cost | 4.9 | 8.8 | |
Net actuarial loss | 111.4 | 108.9 | |
Accumulated other comprehensive income, regulatory assets and regulatory liabilities, pre-tax | 116.3 | 117.7 | |
Defined Benefit Plan, Plan Assets, Benefits Paid | 33.7 | 23.1 | |
Defined Benefit Plan, Benefit Obligation, Benefits Paid | 33.7 | 23.1 | |
Pension [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | |||
Benefit obligation at January 1 | 419.6 | 410.8 | |
Service cost | 5.7 | 5.7 | 7.1 |
Interest cost | 14.2 | 14.7 | 17.3 |
Defined Benefit Plan, Benefit Obligation, (Increase) Decrease for Curtailment | 3 | 2.5 | |
Actuarial (gain) / loss | 28.1 | 9 | |
Benefit obligation at December 31 | 436.9 | 419.6 | 410.8 |
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value of plan assets at January 1 | 341 | 345.4 | |
Actual return / (loss) on plan assets | 44.8 | 13.3 | |
Contributions to plan assets | 5.4 | 5.4 | |
Fair value of plan assets at December 31 | 357.5 | 341 | $ 345.4 |
Defined Benefit Plan, Funded (Unfunded) Status of Plan | (79.4) | (78.6) | |
Current liabilities | (0.4) | (0.4) | |
Noncurrent liabilities | (79) | (78.2) | |
Net asset / (liability) at December 31 | (79.4) | (78.6) | |
Prior service cost | 6.7 | 8.8 | |
Net actuarial loss | 148.3 | 108.9 | |
Accumulated other comprehensive income, regulatory assets and regulatory liabilities, pre-tax | 155 | 117.7 | |
Defined Benefit Plan, Plan Assets, Benefits Paid | 33.7 | 23.1 | |
Defined Benefit Plan, Benefit Obligation, Benefits Paid | 33.7 | 23.1 | |
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 | 92.1 | 97.1 | |
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 | 92.2 | 97.1 | |
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 | 24.2 | 20.6 | |
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 | $ 62.8 | $ 20.6 |
Benefit Plans (Net Periodic Ben
Benefit Plans (Net Periodic Benefit Cost (Income)) (Details) - Pension [Member] - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Service cost | $ 5.7 | $ 5.7 | $ 7.1 |
Interest cost | 14.2 | 14.7 | 17.3 |
Expected return on assets | (22.8) | (22.8) | (22.6) |
Defined Benefit Plan, Curtailments | 4.1 | 3.8 | 0 |
Actuarial gain / (loss) | 5.3 | 4.3 | 5.8 |
Prior service cost | 1.1 | 1.8 | 2 |
Net Periodic benefit cost / (income) before adjustments | $ 7.6 | $ 7.5 | $ 9.6 |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 4.28% | 4.49% | 4.02% |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets | 6.50% | 6.50% | 6.50% |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Service cost | $ 5.7 | $ 5.7 | $ 7.1 |
Interest cost | 14.2 | 14.7 | 17.3 |
Expected return on assets | (22.8) | (22.8) | (22.6) |
Defined Benefit Plan, Curtailments | 5.6 | 5.7 | 0 |
Actuarial gain / (loss) | 8.7 | 7.2 | 9.8 |
Prior service cost | 1.5 | 3 | 3.3 |
Net Periodic benefit cost / (income) before adjustments | $ 12.9 | $ 13.5 | $ 14.9 |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 4.28% | 4.49% | 4.02% |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets | 6.50% | 6.50% | 6.50% |
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, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Defined Benefit Plan Disclosure [Line Items] | |||
Net actuarial (gain) / loss | $ 9.1 | $ 20.9 | $ (3) |
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, Prior Service Cost (Credit), before Tax | 0 | 0 | 0 |
Defined Benefit Plan, Accumulated Other Comprehensive Income, Plan Curtailments | (4.1) | (3.8) | 0 |
Reversal of amortization item, Net actuarial (gain) / loss | (5.3) | (4.3) | (5.8) |
Reversal of amortization item, Prior service cost / (credit) | (1.1) | (1.8) | (2) |
Total recognized in Accumulated other comprehensive income, Regulatory assets and Regulatory liabilities | (1.4) | 11 | (10.8) |
Total recognized in net periodic benefit cost and Accumulated other comprehensive income, Regulatory assets and Regulatory liabilities | 6.2 | 18.5 | (1.2) |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Net actuarial (gain) / loss | 9.1 | 20.9 | (3) |
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, Prior Service Cost (Credit), before Tax | 0 | 0 | 0 |
Defined Benefit Plan, Accumulated Other Comprehensive Income, Plan Curtailments | (5.6) | (5.7) | 0 |
Reversal of amortization item, Net actuarial (gain) / loss | (8.7) | (7.2) | (9.8) |
Reversal of amortization item, Prior service cost / (credit) | (1.5) | (3) | (3.3) |
Total recognized in Accumulated other comprehensive income, Regulatory assets and Regulatory liabilities | (6.7) | 5 | (16.1) |
Total recognized in net periodic benefit cost and Accumulated other comprehensive income, Regulatory assets and Regulatory liabilities | $ 6.2 | $ 18.5 | $ (1.2) |
Benefit Plans (Estimated Amount
Benefit Plans (Estimated Amounts that will be Amortized from Accumulated Other Comprehensive Income, Regulatory Assets And Regulatory Liabilities) (Details) - Scenario, Forecast [Member] - Pension [Member] $ in Millions | Dec. 31, 2018USD ($) |
Defined Benefit Plan Disclosure [Line Items] | |
Net actuarial (gain) / loss | $ 6.4 |
Prior service cost | 0.9 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Net actuarial (gain) / loss | 9.4 |
Prior service cost | $ 1.4 |
Benefit Plans (Weighted Average
Benefit Plans (Weighted Average Assumptions Used to Determine Benefit Obligations) (Details) - Pension [Member] | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Defined Benefit Plan Disclosure [Line Items] | |||
Discount rate for obligations | 3.66% | 4.28% | 4.49% |
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 | 3.66% | 4.28% | 4.49% |
Rate of compensation increases | 3.94% | 3.94% | 3.94% |
Benefit Plans (Weighted Avera86
Benefit Plans (Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost (Income)) (Details) - Pension [Member] | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 4.28% | 4.49% | 4.02% |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets | 6.50% | 6.50% | 6.50% |
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 | 4.28% | 4.49% | 4.02% |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets | 6.50% | 6.50% | 6.50% |
Benefit Plans (Defined Benefits
Benefit Plans (Defined Benefits Plan Assets, Target Allocations) (Details) | Dec. 31, 2017 | Dec. 31, 2016 |
Equity Securities [Member] | ||
Target Allocation | 38.00% | |
Percentage of plan assets | 35.00% | 37.00% |
Debt Securities [Member] | ||
Target Allocation | 56.00% | |
Percentage of plan assets | 55.00% | 53.00% |
Real Estate [Member] | ||
Target Allocation | 6.00% | |
Percentage of plan assets | 10.00% | 10.00% |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Equity Securities [Member] | ||
Target Allocation | 38.00% | |
Percentage of plan assets | 35.00% | 37.00% |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Debt Securities [Member] | ||
Target Allocation | 56.00% | |
Percentage of plan assets | 55.00% | 53.00% |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Real Estate [Member] | ||
Target Allocation | 6.00% | |
Percentage of plan assets | 10.00% | 10.00% |
Benefit Plans (Fair Value Measu
Benefit Plans (Fair Value Measurements for Pension Plan Assets) (Details) - Pension [Member] - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Defined Benefit Plan Disclosure [Line Items] | |||
Total Pension Plan Assets | $ 357.5 | $ 341 | $ 345.4 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Pension Plan Assets | 357.5 | 341 | $ 345.4 |
Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Pension Plan Assets | 321.3 | 307.9 | |
Fair Value, Inputs, Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Pension Plan Assets | 321.3 | 307.9 | |
Fair Value, Inputs, Level 2 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Pension Plan Assets | 36.2 | 33.1 | |
Fair Value, Inputs, Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Pension Plan Assets | 36.2 | 33.1 | |
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 | 78.2 | 81.4 | |
U.S. Equities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 78.2 | 81.4 | |
U.S. Equities [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 78.2 | 81.4 | |
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 | 78.2 | 81.4 | |
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 | 46.3 | 44.4 | |
International Equities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 46.3 | 44.4 | |
International Equities [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 46.3 | 44.4 | |
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 | 46.3 | 44.4 | |
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 | 163.3 | 151.1 | |
Fixed Income Funds [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 163.3 | 151.1 | |
Fixed Income Funds [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 163.3 | 151.1 | |
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 | 163.3 | 151.1 | |
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 | 33.5 | 31 | |
US Treasury Securities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Debt Securities | 33.5 | 31 | |
US Treasury Securities [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Debt Securities | 33.5 | 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 | 33.5 | 31 | |
US Treasury Securities [Member] | Fair Value, Inputs, Level 2 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Debt Securities | 0 | 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 | 0 | |
US Treasury Securities [Member] | Fair Value, Inputs, Level 3 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Debt Securities | 0 | 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 | 0 | |
Core Property Collective Fund [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Other Investments | 36.2 | 33.1 | |
Core Property Collective Fund [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Other Investments | 36.2 | 33.1 | |
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 | 36.2 | 33.1 | |
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 | 36.2 | 33.1 | |
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 | 0 | ||
common collective [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 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 | 0 | ||
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 | 0 | ||
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, 2017USD ($) |
2,016 | $ 28.4 |
2,017 | 28.2 |
2,018 | 27.9 |
2,019 | 27.6 |
2,020 | 27.3 |
2021 - 2025 | 131.3 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
2,016 | 28.4 |
2,017 | 28.2 |
2,018 | 27.9 |
2,019 | 27.6 |
2,020 | 27.3 |
2021 - 2025 | $ 131.3 |
Equity (Narrative) (Details)
Equity (Narrative) (Details) $ / shares in Units, $ in Millions | 12 Months Ended | ||||
Dec. 31, 2017USD ($)$ / sharesshares | Dec. 31, 2016USD ($)shares | Dec. 31, 2015USD ($) | Oct. 01, 2017USD ($) | Jan. 01, 2016USD ($) | |
Class of Stock [Line Items] | |||||
Maximum leverage ratio to allow distribution to shareholder | 0.67 | ||||
Minimum coverage ratio to allow distribution to shareholder | 2.50 | ||||
Retained earnings / (deficit) | $ (2,915.5) | $ (2,820.9) | |||
Common stock, shares authorized | shares | 1,500 | 1,500 | |||
Common stock, shares outstanding | shares | 1 | 1 | |||
Leverage Ratio | 1.50 | ||||
Accounts Payable, Related Parties, Current | $ 3.9 | $ 2 | |||
PUCO Equity Ratio | 33.00% | ||||
Non-cash capital contribution | $ 97.1 | 0 | $ 0 | ||
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Class of Stock [Line Items] | |||||
Retained earnings / (deficit) | $ (319.3) | $ (406.3) | |||
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 | $ 3.9 | $ 2 | |||
PUCO Equity Ratio | 33.00% | ||||
Proceeds from Contributions from Parent | $ 70 | 0 | 0 | ||
Dividends, Common Stock, Cash | 39 | (70) | 50 | ||
Payments of Ordinary Dividends, Common Stock | $ 39 | 70 | 50 | ||
DP&L Series A [Member] | |||||
Class of Stock [Line Items] | |||||
Temporary Equity, Preferred Stock Rate | 3.75% | ||||
Temporary Equity, Redemption Price Per Share | $ / shares | $ 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% | ||||
Temporary Equity, Redemption Price Per Share | $ / shares | $ 102.50 | ||||
DP&L Series B [Member] | |||||
Class of Stock [Line Items] | |||||
Temporary Equity, Preferred Stock Rate | 3.75% | ||||
Temporary Equity, Redemption Price Per Share | $ / shares | $ 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% | ||||
Temporary Equity, Redemption Price Per Share | $ / shares | $ 103 | ||||
DP&L Series C [Member] | |||||
Class of Stock [Line Items] | |||||
Temporary Equity, Preferred Stock Rate | 3.90% | ||||
Temporary Equity, Redemption Price Per Share | $ / shares | $ 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% | ||||
Temporary Equity, Redemption Price Per Share | $ / shares | $ 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 | $ 0 | $ 7.5 | $ 0 | ||
Other Paid-In Capital [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Class of Stock [Line Items] | |||||
Proceeds from Contributions from Parent | (70) | ||||
Dividends, Common Stock, Cash | $ 39 | ||||
Generation [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Class of Stock [Line Items] | |||||
Disposal Group, Including Discontinued Operation, Net Assets | $ 86.2 |
Equity (Preferred Shares Outsta
Equity (Preferred Shares Outstanding) (Details) | Dec. 31, 2017$ / shares |
DP&L Series A [Member] | |
Temporary Equity [Line Items] | |
Temporary Equity, Preferred Stock Rate | 3.75% |
Temporary Equity, Redemption Price Per Share | $ 102.50 |
DP&L Series A [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Temporary Equity [Line Items] | |
Temporary Equity, Preferred Stock Rate | 3.75% |
Temporary Equity, Redemption Price Per Share | $ 102.50 |
DP&L Series B [Member] | |
Temporary Equity [Line Items] | |
Temporary Equity, Preferred Stock Rate | 3.75% |
Temporary Equity, Redemption Price Per Share | $ 103 |
DP&L Series B [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Temporary Equity [Line Items] | |
Temporary Equity, Preferred Stock Rate | 3.75% |
Temporary Equity, Redemption Price Per Share | $ 103 |
DP&L Series C [Member] | |
Temporary Equity [Line Items] | |
Temporary Equity, Preferred Stock Rate | 3.90% |
Temporary Equity, Redemption Price Per Share | $ 101 |
DP&L Series C [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Temporary Equity [Line Items] | |
Temporary Equity, Preferred Stock Rate | 3.90% |
Temporary Equity, Redemption Price Per Share | $ 101 |
Contractual Obligations, Comm92
Contractual Obligations, Commercial Commitments and Contingencies (Narative) (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | |
Public Utility, Property, Plant and Equipment [Line Items] | ||
Due to third parties, current | $ 0.9 | $ 2.3 |
Number of Coal Suppliers | 1 | |
DPLE [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Third party guarantees | $ 38.1 | |
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 | $ 70.6 | |
Long Term Debt Date Range Equity Ownership, Start | 2,019 | |
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 | $ 1,440.8 |
Contractual Obligations, Comm93
Contractual Obligations, Commercial Commitments and Contingenciesl (Schedule Of Contractual Obligations And Commercial Commitments) (Details) $ in Millions | Dec. 31, 2017USD ($) |
Electricity Purchase Commitments [Member] | |
Contractual Obligations, Commercial Commitments And Contingencies [Line Items] | |
Electricity Purchase Commitments | $ 370.9 |
Electricity Purchase Agreements Less Than 1 Year | 178.5 |
Electricity Purchase Agreements in Years 2 and 3 | 171.2 |
Electricity Purchase Agreements in Years 4 and 5 | 21.2 |
Electricity Purchase Agreements, After Year 5 | 0 |
Electricity Purchase Commitments [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Contractual Obligations, Commercial Commitments And Contingencies [Line Items] | |
Electricity Purchase Commitments | 370.9 |
Electricity Purchase Agreements Less Than 1 Year | 178.5 |
Electricity Purchase Agreements in Years 2 and 3 | 171.2 |
Electricity Purchase Agreements in Years 4 and 5 | 21.2 |
Electricity Purchase Agreements, After Year 5 | 0 |
Coal Contracts [Member] | |
Contractual Obligations, Commercial Commitments And Contingencies [Line Items] | |
Total Coal Contracts | 54.9 |
Coal Contracts, Less than 1 year | 54.9 |
Coal Contracts, 2 - 3 years | 0 |
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 | 73 |
Purchase orders and other contractual obligations, Less than 1 year | 18.9 |
Purchase orders and other contractual obligations, 2 - 3 years | 27.1 |
Purchase orders and other contractual obligations, 4 - 5 years | 27 |
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 | 73 |
Purchase orders and other contractual obligations, Less than 1 year | 18.9 |
Purchase orders and other contractual obligations, 2 - 3 years | 27.1 |
Purchase orders and other contractual obligations, 4 - 5 years | 27 |
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, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Jan. 01, 2016 | |
Related Party Transaction [Line Items] | ||||
Deferred Compensation Arrangement with Individual, Compensation Expense | $ 0.4 | $ 0.5 | $ 0.5 | |
Sales to related party | 4.2 | 4.6 | 6.2 | |
Charges for Services Provided | 46.5 | 42.8 | 36 | |
Net payable to the Service Company | (3.9) | (2) | ||
Notes Receivable, Related Parties | 0 | 5 | ||
Investment in trust | 0.3 | 0.3 | ||
Due to Affiliate | (0.6) | 2.5 | ||
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Related Party Transaction [Line Items] | ||||
Deferred Compensation Arrangement with Individual, Compensation Expense | 0.4 | 0.5 | 0.5 | |
Sales to related party | 4.2 | 4.5 | 6.1 | |
Charges for Services Provided | 39 | 38.7 | 30.9 | |
Net payable to the Service Company | (3.9) | (2) | ||
Premiums paid for Insurance Services provided by MVIC | 3.1 | 3.4 | 3.2 | |
Expense recoveries for services provided to DPLER | 0 | 0 | 2.4 | |
Due to Affiliate | (4.8) | 2.5 | ||
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 | ||
Other Current Liabilities [Member] | ||||
Related Party Transaction [Line Items] | ||||
Accounts Payable, Related Parties | 99.3 | |||
Other Current Liabilities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Related Party Transaction [Line Items] | ||||
Accounts Payable, Related Parties | ||||
DPLER [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Related Party Transaction [Line Items] | ||||
Sales to related party | 0 | 0 | 303.3 | |
AES Ohio Generation [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Related Party Transaction [Line Items] | ||||
Charges for Services Provided | 5.4 | 8.7 | 5.2 | |
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 | 15.4 | 9.6 | 15.5 | |
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 | 14.3 | 9.4 | 14.8 | |
Charges for affiliates for non-power goods or services [Member] | Subsidiary of Common Parent [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Related Party Transaction [Line Items] | ||||
Related Party Transaction, Amounts of Transaction | $ 3.7 | $ 5.7 | $ 4.9 |
Business Segments (Narrative) (
Business Segments (Narrative) (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2017mi²customersegment | Dec. 31, 2015USD ($) | |
Segment Reporting Information [Line Items] | ||
Service area, square miles | 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 | 521,000 | |
Service area, square miles | 6,000 | |
Transmission and Distribution [Member] | Operating Segments [Member] | ||
Segment Reporting Information [Line Items] | ||
OVEC Revenue | $ | $ 19.7 |
Business Segments (Segment Fina
Business Segments (Segment Financial Information) (Details) - USD ($) $ in Millions | 6 Months Ended | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Segment Reporting Information [Line Items] | ||||
External customer revenues | $ 1,236.9 | $ 1,427.3 | $ 1,612.8 | |
Intersegment revenues | 0 | 0 | 0 | |
Total revenues | 1,236.9 | 1,427.3 | 1,612.8 | |
Fuel Costs | 210.3 | 268.8 | 259.8 | |
Depreciation and amortization | 106.9 | 132.3 | 134.6 | |
Goodwill, Impairment Loss, Excluding Discontinued Operation | 0 | 0 | 317 | |
Interest expense | 110.1 | 107.7 | 119.8 | |
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest | (119.9) | (793.3) | (231.4) | |
Net loss from continuing operations | (94.6) | (514.5) | (251.4) | |
Discontinued operations, net of tax | 0 | 29.3 | 12.4 | |
Net income (loss) | (94.6) | (485.2) | (239) | |
Cash capital expenditures | 121.5 | 148.5 | 137.2 | |
Total assets (end of year) (a) | $ 2,419.2 | 2,049.2 | 2,419.2 | 3,324.7 |
Fixed-asset impairment (Note 15) | 623.5 | 175.8 | 859 | 0 |
Operating Segments [Member] | Transmission and Distribution [Member] | ||||
Segment Reporting Information [Line Items] | ||||
OVEC Revenue | 19.7 | |||
External customer revenues | 718.9 | 806.7 | 855.5 | |
Intersegment revenues | 1.1 | 1.3 | 1.5 | |
Total revenues | 720 | 808 | 857 | |
Depreciation and amortization | 75.3 | 71 | 71.5 | |
Goodwill, Impairment Loss, Excluding Discontinued Operation | 0 | |||
Interest expense | 30.5 | 25.4 | 29.8 | |
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest | 88.5 | 143 | 188.1 | |
Cash capital expenditures | 85.6 | 83.4 | 98.3 | |
Total assets (end of year) (a) | 1,710.5 | 1,689.4 | 1,710.5 | 1,688.8 |
Fixed-asset impairment (Note 15) | 0 | 0 | ||
Operating Segments [Member] | Generation [Member] | ||||
Segment Reporting Information [Line Items] | ||||
External customer revenues | 507.9 | 611.5 | 770.3 | |
Intersegment revenues | 0 | 0 | 186.6 | |
Total revenues | 507.9 | 611.5 | 956.9 | |
Depreciation and amortization | 20.9 | 55.4 | 72.6 | |
Goodwill, Impairment Loss, Excluding Discontinued Operation | 0 | |||
Interest expense | 0.1 | 0.4 | 2.9 | |
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest | (18.5) | (1,353.9) | (28.7) | |
Cash capital expenditures | 31.3 | 64.2 | 35.2 | |
Total assets (end of year) (a) | 472.3 | 275 | 472.3 | 1,805 |
Fixed-asset impairment (Note 15) | 66.3 | 1,353.5 | ||
Corporate, Non-Segment [Member] | ||||
Segment Reporting Information [Line Items] | ||||
External customer revenues | 10.1 | 9.1 | 6.7 | |
Intersegment revenues | 4.4 | 5.7 | 4.2 | |
Total revenues | 14.5 | 14.8 | 10.9 | |
Depreciation and amortization | 10.7 | 5.9 | (9.5) | |
Goodwill, Impairment Loss, Excluding Discontinued Operation | 317 | |||
Interest expense | 79.5 | 82.2 | 87.4 | |
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest | (189.9) | 417.6 | (390.8) | |
Cash capital expenditures | 4.6 | 0.9 | 3.7 | |
Total assets (end of year) (a) | 673.6 | 468 | 673.6 | 1,170.3 |
Fixed-asset impairment (Note 15) | 109.5 | (494.5) | ||
Consolidation, Eliminations [Member] | ||||
Segment Reporting Information [Line Items] | ||||
External customer revenues | 0 | 0 | (19.7) | |
Intersegment revenues | (5.5) | (7) | (192.3) | |
Total revenues | (5.5) | (7) | (212) | |
Depreciation and amortization | 0 | 0 | 0 | |
Goodwill, Impairment Loss, Excluding Discontinued Operation | 0 | |||
Interest expense | 0 | (0.3) | (0.3) | |
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest | 0 | 0 | 0 | |
Cash capital expenditures | 0 | 0 | 0 | |
Total assets (end of year) (a) | (437.2) | (383.2) | (437.2) | (1,339.4) |
Fixed-asset impairment (Note 15) | 0 | 0 | ||
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Fuel Costs | 0.5 | 5.3 | (9) | |
Depreciation and amortization | 75.3 | 71 | 71.5 | |
Interest expense | 30.5 | 24.7 | 28.9 | |
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest | 88.5 | 143.6 | 189 | |
Net loss from continuing operations | 57.4 | 97.6 | 130 | |
Discontinued operations, net of tax | (40.4) | (870.3) | (23.6) | |
Net income (loss) | 17 | (772.7) | 106.4 | |
Total assets (end of year) (a) | $ 2,035.1 | 1,689.4 | 2,035.1 | |
Fixed-asset impairment (Note 15) | 66.3 | 1,353.5 | 0 | |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Generation [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Discontinued operations, net of tax | $ (40.4) | $ (870.3) | $ (23.6) |
Fixed-asset Impairment (Narrati
Fixed-asset Impairment (Narrative) (Details) - USD ($) $ in Millions | 6 Months Ended | 9 Months Ended | 12 Months Ended | |||
Dec. 31, 2016 | Jun. 30, 2016 | Sep. 30, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fixed-asset impairment (Note 15) | $ 623.5 | $ 175.8 | $ 859 | $ 0 | ||
AES Ohio Generation peakers [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fixed-asset impairment (Note 15) | 109.4 | 1.3 | $ 0 | |||
Peaking Generating Facilities [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fixed-asset impairment (Note 15) | $ 4.7 | |||||
Peaking Generating Facilities [Member] | Fair Value, Inputs, Level 3 [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fair Value | 5.2 | |||||
Killen [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fixed-asset impairment (Note 15) | 230.8 | 27.3 | 75.4 | |||
Impaired Assets to be Disposed of by Method Other than Sale, Amount of Impairment Loss | $ 6.4 | |||||
Killen [Member] | Fair Value, Inputs, Level 3 [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fair Value | 42.8 | $ 84.3 | 7.9 | 42.8 | ||
Stuart [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fixed-asset impairment (Note 15) | 39.1 | 228.5 | ||||
Impaired Assets to be Disposed of by Method Other than Sale, Amount of Impairment Loss | $ 9.8 | |||||
Stuart [Member] | Fair Value, Inputs, Level 3 [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fair Value | 57.4 | $ 3.3 | 57.4 | |||
Miami Fort [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fixed-asset impairment (Note 15) | 149.4 | |||||
Miami Fort [Member] | Fair Value, Inputs, Level 3 [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fair Value | 36.5 | 36.5 | ||||
Zimmer [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fixed-asset impairment (Note 15) | 144.7 | |||||
Zimmer [Member] | Fair Value, Inputs, Level 3 [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fair Value | 23.7 | 23.7 | ||||
Conesville [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fixed-asset impairment (Note 15) | 23.9 | |||||
Conesville [Member] | Fair Value, Inputs, Level 3 [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fair Value | 1.1 | 1.1 | ||||
Hutchings Peakers [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fixed-asset impairment (Note 15) | 1.6 | |||||
Hutchings Peakers [Member] | Fair Value, Inputs, Level 3 [Member] | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Fair Value | $ 1.6 | $ 1.6 |
Discontinued Operations (Detail
Discontinued Operations (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax | $ 0 | $ 49.2 | $ 0 |
Revenues | 0 | 340.9 | |
Cost of revenues | 0 | (307) | |
Operating expenses | (0.7) | (22.5) | |
Income / (loss) from discontinued operations before income tax | 0 | (0.7) | 11.4 |
Income tax expense / (benefit) from discontinued operations | 0 | 19.2 | (1) |
Net income from discontinued operations | $ 0 | 29.3 | 12.4 |
Cash Provided by (Used in) Operating Activities, Discontinued Operations | (0.7) | 35.8 | |
Cash Provided by (Used in) Investing Activities, Discontinued Operations | $ 75.5 | $ 0.5 |
Assets and Liabilities Held-F99
Assets and Liabilities Held-For-Sale and Dispositions (Details) - USD ($) $ in Millions | 6 Months Ended | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 15, 2017 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest | $ (119.9) | $ (793.3) | $ (231.4) | ||
Fixed-asset impairment (Note 15) | $ 623.5 | 175.8 | 859 | 0 | |
Proceeds from sale of business | 70.1 | 75.5 | 1.3 | ||
Miami Fort and Zimmer [Member] | |||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest | 25.7 | (13.5) | 5.6 | ||
Fixed-asset impairment (Note 15) | 294.1 | ||||
Proceeds from sale of business | 50 | ||||
Proceeds from Purchase Price Adjustment | 20.1 | ||||
Gain (Loss) on Disposition of Business | 14 | ||||
AES Ohio Generation peakers [Member] | |||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest | 16.9 | 20 | 23.9 | ||
Accounts receivable, net | 3.8 | ||||
Fixed-asset impairment (Note 15) | 109.4 | $ 1.3 | $ 0 | ||
Inventory, Net | 7.6 | ||||
Disposal Group, Including Discontinued Operations, Taxes Applicable to Subsequent Years | 4.9 | ||||
Property, plant & equipment, net | 233.7 | ||||
Other assets | 0.3 | ||||
Total assets of the disposal group classified as held for sale in the balance sheets | 250.3 | ||||
Accounts payable | 3.9 | ||||
Disposal Group, Including Discontinued Operation, Accrued Income Tax Payable | 3.6 | ||||
Disposal Group, Including Discontinued Operation, Taxes Payable | 4.9 | ||||
Asset Retirement Obligation, Held for Sale | 0.6 | ||||
Other liabilities | 0.2 | ||||
Total liabilities of the disposal group classified as held for sale in the balance sheets | $ 13.2 | ||||
Asset Purchase Agreement Sale Price, Cash | $ 241 |
Generation Separation (Details)
Generation Separation (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Oct. 01, 2017 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||
Long Term Indebtedness, Less than or Equal to | $ 750,000,000 | ||||
Cash Provided by (Used in) Operating Activities, Discontinued Operations | $ (700,000) | $ 35,800,000 | |||
Cash Provided by (Used in) Investing Activities, Discontinued Operations | 75,500,000 | 500,000 | |||
Revenues | 0 | 340,900,000 | |||
Cost of revenues | 0 | (307,000,000) | |||
Income / (loss) from discontinued operations | $ 0 | (700,000) | 11,400,000 | ||
Income tax expense / (benefit) from discontinued operations | 0 | 19,200,000 | (1,000,000) | ||
Net income from discontinued operations | 0 | 29,300,000 | 12,400,000 | ||
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||
Long Term Indebtedness, Less than or Equal to | $ 750,000,000 | $ 750,000,000 | |||
Debt Percentage of Rate Base | 75.00% | ||||
Income / (loss) from discontinued operations | $ (56,300,000) | (1,338,700,000) | (47,500,000) | ||
Income tax expense / (benefit) from discontinued operations | (15,900,000) | (468,400,000) | (23,900,000) | ||
Net income from discontinued operations | (40,400,000) | (870,300,000) | (23,600,000) | ||
THE DAYTON POWER AND LIGHT COMPANY [Member] | Transmission and Distribution [Member] | |||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||
Long-term Debt, Gross | $ 750,000,000 | ||||
THE DAYTON POWER AND LIGHT COMPANY [Member] | Generation [Member] | |||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||
Cash Provided by (Used in) Operating Activities, Discontinued Operations | (10,400,000) | 50,900,000 | 138,700,000 | ||
Cash Provided by (Used in) Investing Activities, Discontinued Operations | 23,400,000 | (50,900,000) | (24,300,000) | ||
Cash Provided by (Used in) Financing Activities, Discontinued Operations | (13,000,000) | 0 | (114,400,000) | ||
Restricted Cash | 29,000,000 | 2,000,000 | |||
Accounts receivable, net | 34,900,000 | 31,300,000 | |||
Inventory, Net | 66,500,000 | 42,000,000 | |||
Disposal Group, Including Discontinued Operations, Taxes Applicable to Subsequent Years | 11,300,000 | 1,800,000 | |||
Property, plant & equipment, net | 156,700,000 | 87,000,000 | |||
Intangible assets, net | 900,000 | 700,000 | |||
Other assets | 25,300,000 | 15,500,000 | |||
Total assets of the disposal group classified as held for sale in the balance sheets | 324,600,000 | 180,300,000 | |||
Accounts payable | 54,800,000 | 12,400,000 | |||
Disposal Group, Including Discontinued Operation, Accrued Income Tax Payable | 3,500,000 | (3,900,000) | |||
Disposal Group, Including Discontinued Operations, Long-Term Debt | 13,400,000 | 300,000 | |||
Disposal Group, Including Discontinued Operation, Taxes Payable | 11,300,000 | ||||
Disposal Group, Including Discontinued Operation, Deferred Tax Liabilities | (120,700,000) | (91,900,000) | |||
Disposal Group, Including Discontinued Operation, Pension Plan Benefit Obligation | 8,200,000 | 9,600,000 | |||
Disposal Group, Including Discontinued Operation, Accumulated Deferred Investment Tax Credit | 16,600,000 | 15,100,000 | |||
Asset Retirement Obligation, Held for Sale | 127,000,000 | 126,300,000 | |||
Other liabilities | 43,600,000 | 24,100,000 | |||
Total liabilities of the disposal group classified as held for sale in the balance sheets | 157,700,000 | 92,000,000 | |||
Disposal Group, Including Discontinued Operation, Accumulated Other Comprehensive Income (Loss), Net of Tax | 2,100,000 | ||||
Disposal Group, Including Discontinued Operation, Net Assets | $ 86,200,000 | ||||
Revenues | 358,400,000 | 557,900,000 | 901,600,000 | ||
Cost of revenues | (191,600,000) | (341,100,000) | (698,300,000) | ||
Disposal Group, Including Discontinued Operation, Operating and Other Expenses | (156,800,000) | (202,000,000) | (250,800,000) | ||
Disposal Group, Including Discontinued Operation, Fixed-Asset Impairment | (66,300,000) | (1,353,500,000) | 0 | ||
Income / (loss) from discontinued operations | (56,300,000) | (1,338,700,000) | (47,500,000) | ||
Income tax expense / (benefit) from discontinued operations | (15,900,000) | (468,400,000) | (23,900,000) | ||
Net income from discontinued operations | (40,400,000) | (870,300,000) | (23,600,000) | ||
Disposal Group, Including Discontinued Operation, Interest Expense | $ 200,000 | $ 500,000 | $ 2,900,000 |
Subsequent Events (Details)
Subsequent Events (Details) - USD ($) $ in Millions | Feb. 26, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Subsequent Event [Line Items] | ||||
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest | $ (119.9) | $ (793.3) | $ (231.4) | |
Property, Plant and Equipment, Additions | 121.5 | 148.5 | 137.2 | |
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Subsequent Event [Line Items] | ||||
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest | $ 88.5 | $ 143.6 | $ 189 | |
Beckjord [Member] | Subsequent Event [Member] | ||||
Subsequent Event [Line Items] | ||||
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest | $ (11.7) | |||
Property, Plant and Equipment, Additions | 15 | |||
Beckjord [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Subsequent Event [Member] | ||||
Subsequent Event [Line Items] | ||||
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest | (12.4) | |||
Property, Plant and Equipment, Additions | $ 15 |
Schedule II Valuation And Qu102
Schedule II Valuation And Qualifying Accounts (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Provision for Uncollectible Accounts [Member] | |||
Valuation and Qualifying Accounts Disclosure [Line Items] | |||
Balance at Beginning of Period | $ 1,159 | $ 835 | $ 898 |
Additions | 3,141 | 4,113 | 3,766 |
Deductions | 3,247 | 3,789 | 3,829 |
Balance at End of Period | 1,053 | 1,159 | 835 |
Provision for Uncollectible Accounts [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Valuation and Qualifying Accounts Disclosure [Line Items] | |||
Balance at Beginning of Period | 1,159 | 835 | 897 |
Additions | 3,141 | 4,113 | 3,766 |
Deductions | 3,247 | 3,789 | 3,828 |
Balance at End of Period | 1,053 | 1,159 | 835 |
Valuation Allowance For Deferred Tax Assets [Member] | |||
Valuation and Qualifying Accounts Disclosure [Line Items] | |||
Balance at Beginning of Period | 38,266 | 39,874 | 40,713 |
Additions | 4,383 | 0 | 3,501 |
Deductions | 6,321 | 1,608 | 4,340 |
Balance at End of Period | 36,328 | 38,266 | 39,874 |
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 | |
Additions | 2,035 | ||
Deductions | 2,291 | ||
Balance at End of Period | $ 113 |