Document and Entity Information
Document and Entity Information | 12 Months Ended |
Dec. 31, 2018USD ($)shares | |
Entity Registrant Name | DPL INC |
Entity Central Index Key | 787,250 |
Document Type | 10-K |
Document Period End Date | Dec. 31, 2018 |
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 | 2,018 |
Document Fiscal Period Focus | FY |
Entity Voluntary Filers | Yes |
Entity Well-known Seasoned Issuer | No |
Entity Small Business | false |
Entity Emerging Growth Company | false |
Entity Shell Company | false |
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, 2018 |
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 | 2,018 |
Document Fiscal Period Focus | FY |
Entity Voluntary Filers | Yes |
Entity Well-known Seasoned Issuer | No |
Entity Small Business | false |
Entity Emerging Growth Company | false |
Entity Shell Company | false |
Entity Public Float | $ | $ 0 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Revenues | $ 775.9 | ||
Cost of revenues: | |||
Net fuel cost | 17.5 | $ 9 | $ 17.4 |
Gross margin | 453.4 | 443.9 | 497.7 |
Utilities Operating Expense, Maintenance and Operations | 156.8 | 186.1 | 213.5 |
Depreciation and amortization | 73.1 | 76.1 | 73.6 |
Taxes, Miscellaneous | 73.5 | 77.1 | 68.4 |
Fixed-asset impairment (Note 14) | 2.8 | 0 | 23.9 |
Gain (Loss) on Sale of Assets and Asset Impairment Charges, excluding Discontinued Operations | 0 | 0.6 | 0.7 |
Gain (Loss) on Disposition of Business | (11.7) | 0 | 0 |
Operating Expenses | 317.9 | 338.7 | 378.7 |
Operating income | 135.5 | 105.2 | 119 |
Other income / (expense), net | |||
Interest expense | (98) | (110) | (107.4) |
Charge for early redemption of debt | (6.5) | (3.3) | (3.1) |
Other income | 0.9 | 1.6 | 3.9 |
Other expense, net | (103.6) | (111.7) | (106.6) |
Income / (loss) from continuing operations before income tax | 31.9 | (6.5) | 12.4 |
Income tax expense / (benefit) from continuing operations | 0.7 | (5) | (2.4) |
Net income / (loss) from continuing operations | 31.2 | (1.5) | 14.8 |
Income / (loss) from discontinued operations before income tax | 70.5 | (127.4) | (806.4) |
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax | (1.6) | 14 | 49.2 |
Income tax expense / (benefit) from discontinued operations | 30 | (20.3) | (257.2) |
Net income / (loss) from discontinued operations | 38.9 | (93.1) | (500) |
Net loss | 70.1 | (94.6) | (485.2) |
Electricity, Purchased [Member] | |||
Cost of revenues: | |||
Cost of Goods and Services Sold | 305 | 291 | 319.1 |
Electricity [Member] | |||
Revenues | 775.9 | 743.9 | 834.2 |
Cost of revenues: | |||
Cost of Goods and Services Sold | 322.5 | 300 | 336.5 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Revenues | 738.7 | ||
Cost of revenues: | |||
Net fuel cost | 2.4 | 0.5 | 5.3 |
Gross margin | 435 | 429.7 | 486 |
Utilities Operating Expense, Maintenance and Operations | 139.7 | 156.5 | 178.4 |
Depreciation and amortization | 74.5 | 75.3 | 71 |
Taxes, Miscellaneous | 73.1 | 76.3 | 68 |
Fixed-asset impairment (Note 14) | 0 | 66.3 | 1,353.5 |
Gain (Loss) on Sale of Assets and Asset Impairment Charges, excluding Discontinued Operations | (0.2) | 0.5 | 0.4 |
Gain (Loss) on Disposition of Business | (12.4) | 0 | 0 |
Operating Expenses | 299.9 | 307.6 | 317 |
Operating income | 135.1 | 122.1 | 169 |
Other income / (expense), net | |||
Interest expense | (27.3) | (30.5) | (24.7) |
Charge for early redemption of debt | (0.6) | (1.1) | (0.5) |
Other income | (2.8) | (2) | (0.2) |
Other expense, net | (30.7) | (33.6) | (25.4) |
Income / (loss) from continuing operations before income tax | 104.4 | 88.5 | 143.6 |
Income tax expense / (benefit) from continuing operations | 17.7 | 31.1 | 46 |
Net income / (loss) from continuing operations | 86.7 | 57.4 | 97.6 |
Income / (loss) from discontinued operations before income tax | 0 | (56.3) | (1,338.7) |
Income tax expense / (benefit) from discontinued operations | 0 | (15.9) | (468.4) |
Net income / (loss) from discontinued operations | 0 | (40.4) | (870.3) |
Dividends on preferred stock | 0 | 0 | 0.7 |
Income / (loss) attributable to common stock | 86.7 | 17 | (773.4) |
Net loss | 86.7 | 17 | (772.7) |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Electricity, Purchased [Member] | |||
Cost of revenues: | |||
Cost of Goods and Services Sold | 301.3 | 289.8 | 316.7 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Electricity [Member] | |||
Revenues | 738.7 | 720 | 808 |
Cost of revenues: | |||
Cost of Goods and Services Sold | $ 303.7 | $ 290.3 | $ 322 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income/(Loss) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Net income / (loss) | $ 70.1 | $ (94.6) | $ (485.2) |
Equity securities activity: | |||
Change in fair value of available-for-sale securities, net of income tax benefit/(expense) | 0 | 0.5 | 0.2 |
Reclassification to earnings of available-for-sale securities, net of income tax expense/(benefit) | 0 | (0.1) | 0 |
Total change in fair value of available-for-sale securities | 0 | 0.4 | 0.2 |
Derivative activity: | |||
Change in derivative fair value, net of income tax benefit/(expense) | (0.1) | 9.6 | 16.1 |
Reclassification of earnings, net of income tax benefit/(expense) | (0.8) | (0.7) | (0.5) |
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives Related to Discontinued Operations, Net of Tax | 3.2 | (7.3) | (29.2) |
Total change in fair value of derivatives | 2.3 | 1.6 | (13.6) |
Pension and postretirement activity: | |||
Prior service cost for the period, net of income tax benefit/(expense) | (2.2) | (0.7) | 0 |
Net loss for the period, net of income tax benefit/(expense) | 1.7 | (1.8) | (4.7) |
Reclassification to earnings, net of income tax benefit/(expense) | 0.6 | 1 | 1 |
Total change in unfunded pension obligation | 0.1 | (1.5) | (3.7) |
Other comprehensive income / (loss) | 2.4 | 0.5 | (17.1) |
Net comprehensive income / (loss) | 72.5 | (94.1) | (502.3) |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Net income / (loss) | 86.7 | 17 | (772.7) |
Equity securities activity: | |||
Change in fair value of available-for-sale securities, net of income tax benefit/(expense) | 0 | 0.5 | 0.2 |
Reclassification to earnings of available-for-sale securities, net of income tax expense/(benefit) | 0 | (0.1) | 0 |
Total change in fair value of available-for-sale securities | 0 | 0.4 | 0.2 |
Derivative activity: | |||
Change in derivative fair value, net of income tax benefit/(expense) | (0.1) | 12.4 | 16.1 |
Reclassification of earnings, net of income tax benefit/(expense) | (0.7) | (0.7) | (0.8) |
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives Related to Discontinued Operations, Net of Tax | 0 | (5.5) | (29.2) |
Total change in fair value of derivatives | (0.8) | 6.2 | (13.9) |
Pension and postretirement activity: | |||
Prior service cost for the period, net of income tax benefit/(expense) | (2.2) | (1.9) | (0.1) |
Net loss for the period, net of income tax benefit/(expense) | 1.7 | (0.8) | (5.9) |
Reclassification to earnings, net of income tax benefit/(expense) | 3.3 | 4.5 | 5.9 |
Total change in unfunded pension obligation | 2.8 | 1.8 | (0.1) |
Other comprehensive income / (loss) | 2 | 8.4 | (13.8) |
Net comprehensive income / (loss) | $ 88.7 | $ 25.4 | $ (786.5) |
Consolidated Statements of Co_2
Consolidated Statements of Comprehensive Income/(Loss) (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income tax (expense)/benefit on unrealized gains (losses) related to available-for-sale securities | $ 0 | $ (0.2) | $ (0.1) |
Other Comprehensive Income (Loss), Reclassification Adjustment for Sale of Securities Included in Net Income, Tax | 0.6 | 0 | 0 |
Income tax (expense)/benefit on unrealized gains (losses) related to derivative activity | 0.1 | (5.3) | (8.8) |
Income tax (expense)/benefit on reclassification of earnings related to derivative activity | 0.4 | 0.3 | 0.5 |
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives Related to Discontinued Operations, Tax | (1.2) | 4.1 | 16.2 |
Income tax (expense)/benefit on prior service cost related to pension and postretirement activity | 0.6 | 0.4 | 0 |
Income tax (expense)/benefit on net loss related to pension and postretirement activity | (0.5) | 1.1 | 2.4 |
Income tax (expense)/benefit on reclassification of earnings related to pension and postretirement activity | (0.2) | (0.5) | (0.6) |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Income tax (expense)/benefit on unrealized gains (losses) related to available-for-sale securities | 0 | (0.2) | (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 | 0.1 | (7.2) | (8.7) |
Income tax (expense)/benefit on reclassification of earnings related to derivative activity | 0.4 | 0.2 | 0.2 |
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives Related to Discontinued Operations, Tax | 0 | 3 | 16.2 |
Income tax (expense)/benefit on prior service cost related to pension and postretirement activity | 0.6 | 1 | 0 |
Income tax (expense)/benefit on net loss related to pension and postretirement activity | (0.4) | 0.4 | 1.1 |
Income tax (expense)/benefit on reclassification of earnings related to pension and postretirement activity | $ (1) | $ (2.3) | $ (1.8) |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Current assets: | ||
Cash and cash equivalents | $ 90.5 | $ 24.5 |
Restricted cash | 21.2 | 0.4 |
Accounts receivable, net | 90.5 | 64.6 |
Inventories | 10.7 | 12.7 |
Taxes applicable to subsequent years | 72.6 | 71.3 |
Regulatory Assets, Current | 41.1 | 23.9 |
Other prepayments and current assets | 12.9 | 12.6 |
Assets held for sale - current | 8.7 | 315.6 |
Total current assets | 348.2 | 525.6 |
Property, plant and equipment: | ||
Property, plant and equipment | 1,615.6 | 1,544.1 |
Less: Accumulated depreciation and amortization | (310.8) | (269.1) |
Property, plant and equipment, net of depreciation | 1,304.8 | 1,275 |
Construction work in process | 32.2 | 46.5 |
Total net property, plant and equipment | 1,337 | 1,321.5 |
Other non-current assets: | ||
Regulatory Assets, Noncurrent | 152.6 | 163.2 |
Intangible assets, net of amortization | 18.4 | 18.8 |
Other deferred assets | 21.6 | 13.8 |
Disposal Group, Including Discontinued Operation, Assets, Noncurrent | 5.3 | 6.3 |
Total other non-current assets | 197.9 | 202.1 |
Total Assets | 1,883.1 | 2,049.2 |
LIABILITIES AND SHAREHOLDER'S EQUITY | ||
Current portion - long-term debt | 103.6 | 4.6 |
Short-term debt | 0 | 10 |
Accounts payable | 58.1 | 48.9 |
Accrued interest | 14.3 | 16.4 |
Accrued taxes | 76.7 | 77.3 |
Customer security deposits | 21.3 | 21.8 |
Regulatory Liability, Current | 34.9 | 14.8 |
Other current liabilities | 22 | 16.2 |
Liabilities held for sale - current | 12.2 | 66.9 |
Total current liabilities | 343.1 | 276.9 |
Non-current liabilities: | ||
Long-term debt | 1,372.3 | 1,700.2 |
Deferred taxes | 116.1 | 113.5 |
Taxes payable | 76.1 | 74.8 |
Regulatory Liability, Noncurrent | 278.3 | 221.2 |
Pension, retiree and other benefits | 82.3 | 90.3 |
Asset Retirement Obligations, Noncurrent | 9.4 | 15.1 |
Other deferred credits | 8 | 8.5 |
Disposal Group, Including Discontinued Operation, Liabilities, Noncurrent | 69.2 | 133 |
Total non-current liabilities | 2,011.7 | 2,356.6 |
Commitments and contingencies | ||
Common shareholder's equity: | ||
Common stock | 0 | 0 |
Other paid-in capital | 2,370.5 | 2,330.4 |
Accumulated other comprehensive income/(loss) | 2.2 | 0.8 |
Retained earnings / (deficit) | (2,844.4) | (2,915.5) |
Total common shareholder's equity | (471.7) | (584.3) |
Total Liabilities and Shareholder's Equity | 1,883.1 | 2,049.2 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Current assets: | ||
Cash and cash equivalents | 45 | 5.2 |
Restricted cash | 21.2 | 0.4 |
Accounts receivable, net | 90.4 | 70.8 |
Inventories | 7.7 | 7.3 |
Taxes applicable to subsequent years | 72.4 | 71.1 |
Regulatory Assets, Current | 41.1 | 23.9 |
Income Taxes Receivable, Current | 19.6 | 6.5 |
Other prepayments and current assets | 13.3 | 14.6 |
Total current assets | 310.7 | 199.8 |
Property, plant and equipment: | ||
Property, plant and equipment | 2,274.4 | 2,247.2 |
Less: Accumulated depreciation and amortization | (988) | (987.3) |
Property, plant and equipment, net of depreciation | 1,286.4 | 1,259.9 |
Construction work in process | 31.7 | 41.5 |
Total net property, plant and equipment | 1,318.1 | 1,301.4 |
Other non-current assets: | ||
Regulatory Assets, Noncurrent | 152.6 | 163.2 |
Intangible assets, net of amortization | 17.2 | 18.8 |
Other deferred assets | 21 | 12.7 |
Total other non-current assets | 190.8 | 194.7 |
Total Assets | 1,819.6 | 1,695.9 |
LIABILITIES AND SHAREHOLDER'S EQUITY | ||
Current portion - long-term debt | 4.6 | 4.6 |
Short-term debt | 0 | 10 |
Accounts payable | 55.8 | 46.6 |
Accrued interest | 0.4 | 0.8 |
Accrued taxes | 75.7 | 76.6 |
Customer security deposits | 21.3 | 21.8 |
Regulatory Liability, Current | 34.9 | 14.8 |
Other current liabilities | 17.5 | 12.9 |
Total current liabilities | 210.2 | 188.1 |
Non-current liabilities: | ||
Long-term debt | 581.5 | 642 |
Deferred taxes | 131.7 | 131 |
Taxes payable | 77.1 | 75.8 |
Regulatory Liability, Noncurrent | 278.3 | 221.2 |
Pension, retiree and other benefits | 83.2 | 91.1 |
Asset Retirement Obligations, Noncurrent | 4.7 | 8 |
Other deferred credits | 7.6 | 8 |
Total non-current liabilities | 1,164.1 | 1,177.1 |
Commitments and contingencies | ||
Common shareholder's equity: | ||
Common stock | 0.4 | 0.4 |
Other paid-in capital | 711.8 | 685.8 |
Accumulated other comprehensive income/(loss) | (35.3) | (36.2) |
Retained earnings / (deficit) | (231.6) | (319.3) |
Total common shareholder's equity | 445.3 | 330.7 |
Total Liabilities and Shareholder's Equity | $ 1,819.6 | $ 1,695.9 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Dec. 31, 2018 | Dec. 31, 2017 |
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 | 50,000,000 | 50,000,000 |
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, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Cash flows from operating activities: | |||
Net income (loss) | $ 70.1 | $ (94.6) | $ (485.2) |
Adjustments to reconcile Net income / (loss) to Net cash from operating activities | |||
Depreciation and amortization | 50.2 | 106.9 | 132.3 |
Amortization of deferred financing costs | 5.5 | 3.6 | 5.6 |
Unrealized loss (gain) on derivatives | (0.2) | (1.7) | (4.3) |
Deferred income taxes | (9.1) | (22.2) | (306.2) |
Charge for early redemption of debt | 6.5 | 3.3 | 3.1 |
Impairment of Long-Lived Assets Held-for-use | 2.8 | 0 | 23.9 |
Impairment of Long-Lived Assets Held-for-use, Including Discontinued Operation | 2.8 | 175.8 | 859 |
Gain (Loss) on Disposition of Business | 13.3 | (14) | (49.2) |
Gain (Loss) on Disposition of Business | (11.7) | 0 | 0 |
Loss / (Gain) on asset disposal, net | (2) | 16.1 | (0.1) |
Changes in certain assets and liabilities: | |||
Accounts receivable | 45.7 | 18.1 | 25.6 |
Inventories | 14.8 | 7.7 | 32 |
Taxes applicable to subsequent years | 0.1 | 2.3 | 0.2 |
Deferred regulatory costs, net | (9.2) | (23.7) | 4.1 |
Accounts payable | (16.3) | (36.3) | 15.1 |
Accrued taxes payable | 37.4 | (3.7) | 45.1 |
Accrued interest payable | (2.1) | (1.3) | (3.7) |
Pension, retiree and other benefits | (3.4) | 4.7 | 3 |
Insurance and claims costs | 1.1 | (2.4) | (0.5) |
Other | 0.7 | (6.9) | (8.8) |
Net cash provided by operating activities | 205.9 | 131.7 | 267.1 |
Cash flows from investing activities: | |||
Capital expenditures | (103.6) | (121.5) | (148.5) |
Proceeds from disposal and sale of business | 234.9 | 70.1 | 0 |
Payments for Removal Costs | (14.5) | 0 | 0 |
Proceeds from Sale of Property, Plant, and Equipment | 10.6 | 0.1 | 0.2 |
Insurance proceeds | 3 | 12.3 | 6.3 |
Other investing activities, net | (0.5) | (0.3) | 0.5 |
Net cash provided by / (used in) investing activities | 129.9 | (39.3) | (141.5) |
Cash flows from financing activities: | |||
Deferred financing costs | 0 | 0 | (8.6) |
Preferred Stock, Redemption Amount | 0 | 0 | (23.5) |
Retirement of debt | (240.5) | (159.5) | (577.8) |
Premium paid for early redemption of debt | 0 | (0.1) | 0 |
Issuance of long-term debt | 0 | 0 | 442.8 |
Borrowings from revolving credit facilities | 30 | 102.5 | 15 |
Repayment of borrowings from revolving credit facilities | (40) | (92.5) | (15) |
Net cash from financing activities | (250.5) | (149.6) | (167.1) |
Net Cash Provided by (Used in) Discontinued Operations | 1.5 | 27.5 | 15.8 |
Cash and cash equivalents: | |||
Net increase / (decrease) in cash | 86.8 | (29.7) | (25.7) |
Restricted Cash and Cash Equivalents | 111.7 | 24.9 | 54.6 |
Supplemental cash flow information: | |||
Interest paid, net of amounts capitalized | 93.7 | 105.2 | 103.8 |
Income taxes paid / (refunded), net | (1.4) | 0 | 0.3 |
Non-cash financing and investing activities: | |||
Accruals for capital expenditures | 10.4 | 12.9 | 16.2 |
Non-cash Proceeds from Sale of Business | 4.1 | 0 | 0 |
Non-cash capital contribution | 40 | 97.1 | 0 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Cash flows from operating activities: | |||
Net income (loss) | 86.7 | 17 | (772.7) |
Adjustments to reconcile Net income / (loss) to Net cash from operating activities | |||
Depreciation and amortization | 74.5 | 87.2 | 120.3 |
Amortization of deferred financing costs | 3.1 | 1.1 | 2.9 |
Unrealized loss (gain) on derivatives | 0 | (1) | (4.2) |
Deferred income taxes | 16.3 | 8.1 | (477.5) |
Charge for early redemption of debt | 0.6 | 1.1 | 0.5 |
Impairment of Long-Lived Assets Held-for-use | 0 | 66.3 | 1,353.5 |
Gain (Loss) on Disposition of Business | (12.4) | 0 | 0 |
Loss / (Gain) on asset disposal, net | 0.2 | 15.7 | (0.1) |
Changes in certain assets and liabilities: | |||
Accounts receivable | 13.5 | 14.6 | (8.3) |
Inventories | (0.3) | 10.3 | 32.2 |
Prepaid taxes | 0 | 0 | 2.7 |
Taxes applicable to subsequent years | (1.3) | 6.4 | 0 |
Deferred regulatory costs, net | (9.2) | (23.7) | 4.1 |
Accounts payable | 3.8 | (48.7) | 14.6 |
Accrued taxes payable | (12.7) | (17.5) | (10.5) |
Accrued interest payable | (0.4) | (1.3) | (2) |
Pension, retiree and other benefits | (2.4) | 4.8 | 3 |
Other | 11 | (5) | (21.3) |
Net cash provided by operating activities | 195.8 | 135.4 | 237.2 |
Cash flows from investing activities: | |||
Capital expenditures | (93.1) | (101.7) | (128.3) |
Payments for Removal Costs | (14.5) | 0 | 0 |
Proceeds from Sale of Property, Plant, and Equipment | 10.6 | 0 | 0.2 |
Insurance proceeds | 0.4 | 12.5 | 6.1 |
Other investing activities, net | (0.3) | (0.3) | 0.4 |
Net cash provided by / (used in) investing activities | (96.9) | (89.5) | (121.6) |
Cash flows from financing activities: | |||
Dividends paid on preferred stock | 0 | 0 | (0.7) |
Deferred financing costs | 0 | 0 | (8.5) |
Preferred Stock, Redemption Amount | 0 | 0 | (23.5) |
Retirement of debt | (64.5) | (104.5) | (445.3) |
Proceeds from Contributions from Parent | 80 | 70 | 0 |
Premium paid for early redemption of debt | 0 | (0.4) | 0 |
Issuance of long-term debt | 0 | 0 | 442.8 |
Borrowings from revolving credit facilities | 30 | 40 | 0 |
Repayment of borrowings from revolving credit facilities | (40) | (30) | 0 |
Dividends paid on common stock to parent | (43.8) | (39) | (70) |
Borrowings from related party | 0 | 30 | 10 |
Repayment of borrowings from related party | 0 | (35) | (40) |
Net cash from financing activities | (38.3) | (68.9) | (135.2) |
Net Cash Provided by (Used in) Discontinued Operations | 0 | 27 | 15.8 |
Cash and cash equivalents: | |||
Net increase / (decrease) in cash | 60.6 | 4 | (3.8) |
Restricted Cash and Cash Equivalents | 66.2 | 5.6 | 1.6 |
Supplemental cash flow information: | |||
Interest paid, net of amounts capitalized | 22.9 | 28.4 | 21.4 |
Income taxes paid / (refunded), net | 13.1 | 28.1 | 0.3 |
Non-cash financing and investing activities: | |||
Accruals for capital expenditures | 10.8 | 19.7 | 14.8 |
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 | $ 0 | 7.5 |
Generation [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Non-cash financing and investing activities: | |||
Disposal Group, Including Discontinued Operation, Net Assets | $ (10) | $ 0 |
Consolidated Statements of Shar
Consolidated Statements of Shareholders' Equity - USD ($) $ in Millions | Total | Common Stock [Member] | Other Paid-In Capital [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Other Comprehensive Income/(Loss) [Member] | Retained Earnings [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [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]Reclassification out of Accumulated Other Comprehensive Income [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]Accumulated Other Comprehensive Income/(Loss) [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]Retained Earnings [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | Generation [Member]THE DAYTON POWER AND LIGHT COMPANY [Member] |
Other Comprehensive Income (Loss), Net of Tax | $ (17.1) | $ (13.8) | |||||||||||||
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 | |||||||||||||
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 | ||||||||||||||
Disposal Group, Including Discontinued Operation, Net Assets | $ 0 | ||||||||||||||
Other Comprehensive Income (Loss), Net of Tax | 0.5 | $ 1.6 | 8.4 | $ 6.2 | |||||||||||
Preferred Stock Redemption Premium | 5.1 | ||||||||||||||
Net comprehensive income/ (loss) | (94.1) | 25.4 | |||||||||||||
Net loss | (94.6) | 17 | |||||||||||||
Common stock dividends | 39 | (39) | |||||||||||||
Stockholders' Equity Note, Spinoff Transaction | (2.1) | (2.1) | |||||||||||||
Proceeds from Contributions from Parent | 70 | (70) | |||||||||||||
Preferred stock dividends | (88.3) | ||||||||||||||
Other | 0.3 | 0.3 | 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 | 41,172,173 | |||||||||||||
Non-cash capital contribution | 97.1 | 97.1 | |||||||||||||
Other Comprehensive Income (Loss), Net of Tax | 2.4 | 2.3 | 2 | (0.8) | |||||||||||
Net comprehensive income/ (loss) | 72.5 | 88.7 | |||||||||||||
Net loss | 70.1 | 86.7 | |||||||||||||
Common stock dividends | (43.8) | (43.8) | |||||||||||||
Proceeds from Contributions from Parent | 80 | (80) | |||||||||||||
Preferred stock dividends | (10) | ||||||||||||||
Other | 0.1 | 0.1 | $ (1) | 1 | (0.3) | (0.2) | $ (1.1) | 1 | |||||||
Balance at Dec. 31, 2018 | (471.7) | $ 0 | 2,370.5 | $ 2.2 | $ (2,844.4) | 445.3 | $ 0.4 | $ 711.8 | $ (35.3) | $ (231.6) | |||||
Balance (in shares) at Dec. 31, 2018 | 1 | ||||||||||||||
Non-cash capital contribution | 40 | $ 40 | |||||||||||||
AOCI reclassed to Retained Earnings before tax | Adjustments for New Accounting Pronouncement [Member] | 1.6 | 1.7 | |||||||||||||
AOCI reclassed to Retained Earnings, net of tax | (1) | $ 0 | (1.1) | $ 0 | |||||||||||
AOCI reclassed to Retained Earnings, net of tax | Adjustments for New Accounting Pronouncement [Member] | $ 1 | $ 1.1 | |||||||||||||
Disposal Group, Including Discontinued Operation, Net Assets | $ (10) |
Consolidated Statements of Sh_2
Consolidated Statements of Shareholders' Equity (Parenthetical) - $ / shares | Dec. 31, 2018 | Dec. 31, 2017 |
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 | 50,000,000 | 50,000,000 |
Overview and Summary of Signifi
Overview and Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2018 | |
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 one reportable segment, the Utility segment. See Note 13 – Business Segments for more information relating to our reportable segment. 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, DPL's wholly-owned subsidiary , 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 525,000 customers located in West Central Ohio. DP&L provides 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 all of the generation for its SSO customers through a competitive bid process. Through September 30, 2017, DP&L owned undivided interests in multiple 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, excluding the Beckjord Facility and Hutchings EGU, 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. DPL’s other primary subsidiaries include MVIC and AES Ohio Generation. MVIC is our captive insurance company that provides insurance services to DPL and our subsidiaries. AES Ohio Generation owns an undivided interest in Conesville Unit 4 . AES Ohio Generation sells all of its energy and capacity into the wholesale market. DPL's subsidiaries are wholly-owned. 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 March 27, 2018, DPL and AES Ohio Generation completed the sale of their Peaker assets to Kimura Power, LLC. Further, on May 31, 2018, DPL and AES Ohio Generation retired the Stuart Station coal-fired and diesel-fired generating units and the Killen Station coal-fired generating unit and combustion turbine, as planned. See Note 15 – Discontinued Operations for additional information. 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 or overcollections of riders. DPL and its subsidiaries employed 659 people at January 31, 2019 , of which 647 were employed by DP&L. Approximately 57% of all DPL employees are under a collective bargaining agreement. 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. Through June 2018, DP&L had undivided ownership interests in numerous transmission facilities. These undivided interests in jointly-owned facilities were accounted for on a pro rata basis in the Consolidated Financial Statements. In June 2018, DP&L closed on a transmission asset transaction with Duke and AEP, where ownership stakes in certain previously co-owned transmission assets were exchanged to eliminate co-ownership. Each previously co-owned transmission asset became wholly-owned by one of DP&L , Duke or AEP after the transaction. 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; 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. Revenue is recognized upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. 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. The power sales and purchases within DP&L’s service territory are reported on a net hourly basis as revenues or purchased power on our Consolidated Statements of Operations. We record expenses when purchased electricity is received and when expenses are incurred. All of the power produced at the generation station is sold to an RTO. We record expenses when purchased electricity is received and when expenses are incurred. For additional information, see Note 14 – Revenue . 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 our jointly-held station 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 $0.5 million , $1.7 million and $2.1 million in the years ended December 31, 2018 , 2017 and 2016 , 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. Repairs and Maintenance Costs associated with maintenance activities 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 4.3% in 2018 , 5.0% in 2017 and 6.1% in 2016 (including property classified in non-current assets of discontinued operations and held-for-sale businesses in 2017 and 2016). Depreciation expense was $66.5 million , $70.4 million and $67.0 million for the years ended December 31, 2018 , 2017 and 2016 , 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 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 . Amortization expense was $6.6 million , $5.7 million and $6.6 million for the years ended December 31, 2018 , 2017 and 2016 , respectively. The estimated amortization expense of this internal-use software over the next five years is $15.0 million ( $4.2 million in 2019, $3.2 million in 2020, $3.0 million in 2021, $2.6 million in 2022 and $2.0 million in 2023 ). 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 or liability with a corresponding deferred tax liability or asset. Investment tax credits that reduced federal income taxes in the years they arose have been deferred and are being amortized to income over the useful lives of the properties in accordance with regulatory treatment . See Note 3 – Regulatory Matters for additional information. DPL and its subsidiaries file U.S. federal income tax returns as part of the consolidated U.S. income tax return filed by AES. The consolidated tax liability is allocated to each subsidiary based on the separate return method which is specified in our tax allocation agreement and which provides a consistent, systematic and rational approach . See Note 8 – Income Taxes for additional information. Financial Instruments Our Master Trust investments in debt and equity financial instruments of publicly traded entities are classified as equity investments. These equity securities are carried at fair value and unrealized gains and losses on these securities are recorded in Other income. As these financial instruments are held to be used for the benefit of employees participating in employee benefit plans and are not used for general operating purposes, they are classified as non-current in Other deferred assets on the Consolidated Balance Sheets. 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 15 – Discontinued Operations for further information. Discontinued Operations Discontinued operations reporting occurs only when the disposal of a business or a group of assets 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 Consolidated 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 15 – 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 Consolidated Statements of Operations. The amounts for the years ended December 31, 2018 , 2017 and 2016 , were $51.7 million , $49.4 million and $50.9 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. The following table provides a summary of cash, cash equivalents, and restricted cash amounts reported on the Consolidated Balance Sheet that reconcile to the total of such amounts as shown on the Consolidated Statements of Cash Flows: $ in millions December 31, 2018 December 31, 2017 Cash and cash equivalents $ 90.5 $ 24.5 Restricted cash 21.2 0.4 Cash, Cash Equivalents, and Restricted Cash, End of Period $ 111.7 $ 24.9 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 interest rate hedges to manage the interest rate risk of our variable rate debt. 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 and our subsidiaries 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 $4.1 million and $3.0 million at December 31, 2018 and 2017 , 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 $4.3 million and $4.4 million at December 31, 2018 and 2017 , 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 from actuarial gains or losses related to our regulated operations, that would otherwise be recognized in AOCI, recorded as a regulatory asset as this can be recovered through future rates. Such changes that are not related to our regulated operations are recognized in AOCI. 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. See Note 9 – 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 12 – 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 an unconsolidated subsidiary. The Trust holds mandatorily redeemable trust capital securities. The investment in the Trust, which amounts to $0.2 million and $0.3 million at December 31, 2018 and 2017 , 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, 2018 and 2017 , respectively, that was established upon the Trust’s deconsolidation in 2003. See Note 7 – Long-term 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 adopted in 2018 The following table provides a brief description of recently adopted accounting pronouncements that had an impact on our consolidated financial statements. Accounting pronouncements not listed below were assessed and determined to be either not applicable or did not 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 2018-15, Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract This standard aligns the accounting for implementation costs incurred for a cloud computing arrangement that is a service with the requirement for capitalizing implementation costs associated with developing or obtaining internal-use software. October 1, 2018 We elected to early-adopt this standard on a prospective basis, effective for fiscal year 2018. The adoption of this standard did not have a material impact on our financial statements. 2018-14, Compensation— Retirement Benefits — Defined Benefit Plans — General (Subtopic 715-20): Disclosure Framework This standard modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. Early adoption elected, January 1, 2018 Impact limited to changes in financial statement disclosures. 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 costs associated with defined benefit plans and updates the guidance so that only the service cost component will be eligible for capitalization. January 1, 2018 For the years ended December 31, 2017 and 2016 we reclassified non-service pension costs from Operating expenses to Other expense of $2.2 million and $3.2 million, respectively. 2016-18, Statement of Cash Flows (Topic 230): 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 For the years ended December 31, 2017 and 2016, we reclassified from "Net cash used in investing activities" to "Net increase / (decrease) in cash, cash equivalents and restricted cash" $27.1 million and ($11.8) million, respectively. 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities The standard significantly revises an entity’s accounting related to (1) classification and measurement of investments in equity securities and (2) the presentation of certain fair value changes for financial liabilities measured at fair value. It also amends certain disclosures of financial instruments. Transition method: modified retrospective. Prospective for equity investments without readily determinable fair value. January 1, 2018 We adopted this standard January 1, 2018. At that date, we transferred $1.6 million ($1.0 million net of tax) of unrealized gains from AOCI to Accumulated Deficit. 2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-10, 2017-13, Revenue from Contracts with Customers (Topic 606) See discussion of the ASU below. January 1, 2018 See impact upon adoption of the standard below. Adoption of FASC Topic 606, "Revenue from Contracts with Customers" On January 1, 2018, we adopted ASU 2014-09, "Revenue from Contracts with Customers", and its subsequent corresponding updates ("FASC 606"). The core principle of this standard 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. We applied the modified retrospective method of adoption to those contracts which were not completed as of January 1, 2018. Results for reporting periods beginning January 1, 2018 are presented under FASC 606, while prior period amounts were not adjusted and continue to be reported in accordance with our historic accounting under the previous revenue recognition standard. For contracts that were modified before January 1, 2018, we have not retrospectively restated the contracts for modifications. We instead reflected the aggregate effect of all modifications when identifying the satisfied and unsatisfied performance obligations, determining the transaction price and allocating the transaction price. We do not expect the adoption of the new revenue standard to have a material impact to our net income on an ongoing basis. There was no cumulative effect to our January 1, 2018 Consolidated Balance Sheet resulting from the adoption of FASC 606. New accounting pronouncements issued but not yet effective - The following table provides a brief description of recent accounting pronouncements that could have a material impact on our consolidated financial statements. Accounting pronouncements not listed below were assessed and determined to be either not applicable or are expected to have no material impact on our consolidated financial statements. Accounting Standard Description Date of Adoption Effect on the financial statements upon adoption 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 do not expect any impact on our consolidated financial statements upon adoption of the standard on January 1, 2019. 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 in the period in which it settles. Transition method: modified retrospective with the cumulative effect adjustment recorded to the opening balance of retained earnings as of the initial application date. Prospective for presentation and disclosures. January 1, 2019. Early adoption is permitted. We are currently evaluating the impact of adopting the standard on our cons |
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 525,000 customers located in West Central Ohio. DP&L provides 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 all of the generation for its SSO customers through a competitive bid process. Through September 30, 2017, DP&L owned undivided interests in multiple 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, excluding the Beckjord Facility and Hutchings EGU, 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. 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. 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 or overcollections of riders. DP&L employed 647 people at January 31, 2019 . Approximately 58% of all employees are under a collective bargaining agreement. Financial Statement Presentation DP&L does not have any subsidiaries. Through June 2018, DP&L had undivided ownership interests in numerous transmission facilities. These undivided interests in jointly-owned facilities were accounted for on a pro rata basis in the Financial Statements. In June 2018, DP&L closed on a transmission asset transaction with Duke and AEP, where ownership stakes in certain previously co-owned transmission assets were exchanged to eliminate co-ownership. Each previously co-owned transmission asset became wholly-owned by one of DP&L , Duke or AEP after the transaction. 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. 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. Revenue is recognized upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. 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. For additional information, see Note 13 – Revenue . 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 $0.5 million , $1.5 million and $2.0 million for the years ended December 31, 2018 , 2017 and 2016 , 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 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 3.0% in 2018 , 3.4% in 2017 and 4.6% in 2016 . Depreciation expense was $68.2 million , $69.6 million and $64.3 million for the years ended December 31, 2018 , 2017 and 2016 , 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 Amortization expense was $6.3 million , $5.7 million and $6.7 million for the years ended December 31, 2018 , 2017 and 2016 , respectively. The estimated amortization expense of this internal-use software over the next five years is $11.1 million ( $3.5 million in 2019, $2.4 million in 2020, $2.2 million in 2021, $1.8 million in 2022 and $1.2 million in 2023 ). 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 or liability with a corresponding deferred tax liability or asset. 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 Our Master Trust investments in debt and equity financial instruments of publicly traded entities are classified as equity investments. These equity securities are carried at fair value and unrealized gains and losses on these securities are recorded in Other income. As these financial instruments are held to be used for the benefit of employees participating in employee benefit plans and are not used for general operating purposes, they are classified as non-current in Other deferred assets on the Consolidated Balance Sheets. 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 14 – Generation Separation for further information. Discontinued Operations Discontinued operations reporting occurs only when the disposal of a business or a group of assets 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 14 – Generation Separation for further information. Generation Separation With the transfer of DP&L's generation assets to an affiliate (see Note 14 – 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 and 2016 and in the notes to the financial statements. 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, 2018 , 2017 and 2016 were $51.7 million , $49.4 million and $50.9 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. The following table provides a summary of cash, cash equivalents, and restricted cash amounts reported on the Balance Sheet that reconcile to the total of such amounts as shown on the Statements of Cash Flows: $ in millions December 31, 2018 December 31, 2017 Cash and cash equivalents $ 45.0 $ 5.2 Restricted cash 21.2 0.4 Cash, Cash Equivalents, and Restricted Cash, End of Period $ 66.2 $ 5.6 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 interest rate hedges to manage the interest rate risk of our variable rate debt. 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 and other DPL subsidiaries for workers’ compensation, general liability, and property damage on an ongoing basis. DP&L is responsible for claims 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 third-party providers of approximately $4.3 million and $4.4 million at December 31, 2018 and 2017 , 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 from actuarial gains or losses related to our regulated operations, that would otherwise be recognized in AOCI, recorded as a regulatory asset as this can be recovered through future rates. Such changes that are not related to our regulated operations are recognized in AOCI. 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. 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 adopted in 2018 The following table provides a brief description of recently adopted accounting pronouncements that had an impact on our consolidated financial statements. Accounting pronouncements not listed below were assessed and determined to be either not applicable or did not 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 2018-15, Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract This standard aligns the accounting for implementation costs incurred for a cloud computing arrangement that is a service with the requirement for capitalizing implementation costs associated with developing or obtaining internal-use software. October 1, 2018 We elected to early-adopt this standard on a prospective basis, effective for fiscal year 2018. The adoption of this standard did not have a material impact on our financial statements. 2018-14, Compensation— Retirement Benefits — Defined Benefit Plans — General (Subtopic 715-20): Disclosure Framework This standard modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. Early adoption elected, January 1, 2018 Impact limited to changes in financial statement disclosures. 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 costs associated with defined benefit plans and updates the guidance so that only the service cost component will be eligible for capitalization. January 1, 2018 For the years ended December 31, 2017 and 2016 we reclassified non-service pension costs from Operating expenses to Other expense of ($1.5) million and ($0.9) million, respectively. 2016-18, Statement of Cash Flows (Topic 230): 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 For the years ended December 31, 2017 and 2016, we reclassified from "Net cash used in investing activities" to "Net increase / (decrease) in cash, cash equivalents and restricted cash" $26.6 million and ($11.9) million, respectively. 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities The standard significantly revises an entity’s accounting related to (1) classification and measurement of investments in equity securities and (2) the presentation of certain fair value changes for financial liabilities measured at fair value. It also amends certain disclosures of financial instruments. January 1, 2018 We adopted this standard January 1, 2018. At that date, we transferred $1.7 million ($1.1 million net of tax) of unrealized gains from AOCI to Retained Earnings. 2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-10, 2017-13, Revenue from Contracts with Customers (Topic 606) See discussion of the ASU below. January 1, 2018 See impact upon adoption of the standard below. Adoption of FASC Topic 606, "Revenue from Contracts with Customers" On January 1, 2018, we adopted ASU 2014-09, "Revenue from Contracts with Customers", and its subsequent corresponding updates ("FASC 606"). The core principle of this standard 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. We applied the modified retrospective method of adoption to those contracts which were not completed as of January 1, 2018. Results for reporting periods beginning January 1, 2018 are presented under FASC 606, while prior period amounts were not adjusted and continue to be reported in accordance with our historic accounting under the previous revenue recognition standard. For contracts that were modified before January 1, 2018, we have not retrospectively restated the contracts for modifications. We instead reflected the aggregate effect of all modifications when identifying the satisfied and unsatisfied performance obligations, determining the transaction price and allocating the transaction price. We do not expect the adoption of the new revenue standard to have a material impact to our net income on an ongoing basis. There was no cumulative effect to our January 1, 2018 Balance Sheet resulting from the adoption of FASC 606. New accounting pronouncements issued but not yet effective - The following table provides a brief description of recent accounting pronouncements that could have a material impact on our financial statements. Accounting pronouncements not listed below were assessed and determined to be either not applicable or are expected to have no material impact on our financial statements. Accounting Standard Description Date of Adoption Effect on the financial statements upon adoption New Accounting Standards Issued but Not Yet Effective 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 do not expect any impact on our financial statements upon adoption of the standard on January 1, 2019. 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 in the period in which it settles. January 1, 2019. Early adoption is permitted. We are currently evaluating the impact of adopting the standard on our financial statements. 2018-19, 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. For trade and other receivables, held-to-maturity debt securities, loans and other instruments, entities will be required to use a new forward-looking "expected loss" model that generally will result in the earlier recognition of allowance for losses. For available-for-sale debt securities with unrealized losses, entities will measure credit losses as it is done today, except that the losses will be recognized as an allowance rather than a reduction in the amortized cost of the securities. 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, 2018-01, 2018-10, 2018-11, 2018-20 See discussion of the ASU below. January 1, 2019. Early adoption is permitted. We will adopt the standard on January 1, 2019; see below for the evaluation of the impact of its adoption on our financial statements. Adoption of FASC Topic 842, "Leases" 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 must be adopted using a modified retrospective approach. The FASB has provided an optional transition method, which we have elected, that allows entities to continue to apply the guidance in FASC 840 Leases to the comparative periods presented in the year of adoption. Under this transition method, we will apply the transition provisions starting on January 1, 2019. We have elected to apply a package of practical expedients that allow lessees and lessors 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. We have also elected to apply an optional transition practical expedient for land easements that allows an entity to continue applying its current accounting policy for all land easements that exist before the standard’s effective date that were not previously accounted for under FASC 840. We 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 assets and related liabilities. Additionally, the implementation team has been working on the configuration of a lease accounting tool that will support the implementation and the subsequent accounting. The implementation team has also evaluated changes to our business processes, systems and controls to support recognition and disclosure under the new standard. Under FASC 842, it is expected that fewer contracts will contain a lease. However, due to the elimination of the 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 includes the fair value of the plant after the contract period but does not include any variable paymen |
Supplemental Financial Informat
Supplemental Financial Information | 12 Months Ended |
Dec. 31, 2018 | |
Supplemental Financial Information [Line Items] | |
Additional Financial Information Disclosure [Text Block] | Supplemental Financial Information December 31, $ in millions 2018 2017 Accounts receivable, net Customer receivables $ 55.8 $ 45.2 Unbilled revenue 16.8 18.0 Due from PJM transmission enhancement settlement (a) 16.5 — Other 2.3 2.5 Provisions for uncollectible accounts (0.9 ) (1.1 ) Total accounts receivable, net $ 90.5 $ 64.6 Inventories, at average cost Fuel and limestone $ 1.9 $ 4.1 Materials and supplies 8.3 8.1 Other 0.5 0.5 Total inventories, at average cost $ 10.7 $ 12.7 (a) - See Note 3 – Regulatory Matters for more information. Accumulated Other Comprehensive Income / (Loss) The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the years ended December 31, 2018 , 2017 and 2016 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 2018 2017 2016 Gains and losses on equity securities (Note 5): Other deductions $ — $ (0.1 ) $ — Income tax expense — — — Net of income taxes — (0.1 ) — Gains and losses on cash flow hedges (Note 6): Interest expense (1.2 ) (1.0 ) (1.0 ) Income tax benefit 0.4 0.3 0.5 Net of income taxes (0.8 ) (0.7 ) (0.5 ) Gain / (loss) from discontinued operations 4.4 (11.4 ) (45.4 ) Tax benefit / (expense) from discontinued operations (1.2 ) 4.1 16.2 Net of income taxes 3.2 (7.3 ) (29.2 ) Amortization of defined benefit pension items (Note 9): Other income 0.8 1.5 1.6 Income tax expense (0.2 ) (0.5 ) (0.6 ) Net of income taxes 0.6 1.0 1.0 Total reclassifications for the period, net of income taxes $ 3.0 $ (7.1 ) $ (28.7 ) The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the years ended December 31, 2018 and 2017 are as follows: $ in millions Gains / (losses) on equity securities Gains / (losses) on cash flow hedges Change in unfunded pension obligation Total 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 Other comprehensive loss before reclassifications — (0.1 ) (0.5 ) (0.6 ) Amounts reclassified from accumulated other comprehensive income to earnings — 2.4 0.6 3.0 Net current period other comprehensive income — 2.3 0.1 2.4 Amounts reclassified from accumulated other comprehensive income to accumulated deficit (a) (1.0 ) — — (1.0 ) Balance at December 31, 2018 $ — $ 17.0 $ (14.8 ) $ 2.2 (a) ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” was effective as of January 1, 2018. This ASU requires the change in the fair value of equity instruments to be recorded in income rather than in OCI. Equity Instruments were defined to include all mutual funds, regardless of the underlying investments. Therefore, as of January 1, 2018, AOCI of $1.6 million ( $1.0 million net of tax) was reversed to Accumulated Deficit. |
Supplemental Financial Information | December 31, $ in millions 2018 2017 Accounts receivable, net Customer receivables $ 55.8 $ 45.2 Unbilled revenue 16.8 18.0 Due from PJM transmission enhancement settlement (a) 16.5 — Other 2.3 2.5 Provisions for uncollectible accounts (0.9 ) (1.1 ) Total accounts receivable, net $ 90.5 $ 64.6 Inventories, at average cost Fuel and limestone $ 1.9 $ 4.1 Materials and supplies 8.3 8.1 Other 0.5 0.5 Total inventories, at average cost $ 10.7 $ 12.7 |
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 2018 2017 Accounts receivable, net Customer receivables $ 53.3 $ 44.2 Unbilled revenue 16.8 18.0 Amounts due from partners in jointly-owned stations — 5.0 Due from PJM transmission enhancement settlement (a) 16.5 — Due from affiliates 2.3 0.6 Other 2.4 4.1 Provisions for uncollectible accounts (0.9 ) (1.1 ) Total accounts receivable, net $ 90.4 $ 70.8 Inventories, at average cost Materials and supplies $ 7.1 $ 6.9 Other 0.6 0.4 Total inventories, at average cost $ 7.7 $ 7.3 (a) - See Note 3 – Regulatory Matters for more information. Accumulated Other Comprehensive Income / (Loss) The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the years ended December 31, 2018 , 2017 and 2016 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 2018 2017 2016 Gains and losses on equity securities activity (Note 5): Other deductions $ — $ (0.1 ) $ — Income tax expense — — — Net of income taxes — (0.1 ) — Gains and losses on cash flow hedges (Note 6): Interest expense (1.1 ) (0.9 ) (1.0 ) Income tax benefit 0.4 0.2 0.2 Net of income taxes (0.7 ) (0.7 ) (0.8 ) Loss from discontinued operations — (8.5 ) (45.4 ) Income tax benefit from discontinued operations — 3.0 16.2 Net of income taxes — (5.5 ) (29.2 ) Amortization of defined benefit pension items (Note 9): Other income 4.3 6.8 7.7 Income tax expense (1.0 ) (2.3 ) (1.8 ) Net of income taxes 3.3 4.5 5.9 Total reclassifications for the period, net of income taxes $ 2.6 $ (1.8 ) $ (24.1 ) The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the years ended December 31, 2018 and 2017 are as follows: $ in millions Gains / (losses) on equity securities Gains / (losses) on cash flow hedges Change in unfunded pension obligation Total 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 ) Other comprehensive loss before reclassifications — (0.1 ) (0.5 ) (0.6 ) Amounts reclassified from accumulated other comprehensive income / (loss) to earnings — (0.7 ) 3.3 2.6 Net current period other comprehensive income / (loss) — (0.8 ) 2.8 2.0 Amounts reclassified from accumulated other comprehensive income to accumulated deficit (a) (1.1 ) — — (1.1 ) Balance at December 31, 2018 $ — $ 0.6 $ (35.9 ) $ (35.3 ) (a) ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” was effective as of January 1, 2018. This ASU requires the change in the fair value of equity instruments to be recorded in income rather than in OCI. Equity Instruments were defined to include all mutual funds, regardless of the underlying investments. |
Supplemental Financial Information | Supplemental Financial Information December 31, $ in millions 2018 2017 Accounts receivable, net Customer receivables $ 53.3 $ 44.2 Unbilled revenue 16.8 18.0 Amounts due from partners in jointly-owned stations — 5.0 Due from PJM transmission enhancement settlement (a) 16.5 — Due from affiliates 2.3 0.6 Other 2.4 4.1 Provisions for uncollectible accounts (0.9 ) (1.1 ) Total accounts receivable, net $ 90.4 $ 70.8 Inventories, at average cost Materials and supplies $ 7.1 $ 6.9 Other 0.6 0.4 Total inventories, at average cost $ 7.7 $ 7.3 (a) - See Note 3 – Regulatory Matters for more information. |
Regulatory Matters (Notes)
Regulatory Matters (Notes) | 12 Months Ended |
Dec. 31, 2018 | |
Schedule of Regulatory Assets and Liabilities [Text Block] | Regulatory Matters Distribution Rate Order On September 26, 2018 the PUCO issued the DRO establishing new base distribution rates for DP&L , which became effective October 1, 2018. The DRO approved, without modification, a stipulation and recommendation previously filed by DP&L , along with various intervening parties and the PUCO staff. The DRO established a revenue requirement of $248.0 million for DP&L 's electric service base distribution rates which reflects an increase to distribution revenues of approximately $29.8 million per year. In addition to the increase in base distribution rates, and among other matters, the DRO provides for a return on equity of 9.999% and a cost of long-term debt of 4.8% and for the following items: DIR – The DRO authorized DP&L to begin charging a Distribution Investment Rider ("DIR") set initially at $12.2 million annually, effective October 1, 2018. The DIR revenue requirement shall be updated quarterly and will increase as DP&L makes qualified investments in its distribution network, subject to annual revenue limits which increase each year; the revenue limit for 2019 is $22.0 million . The DIR will expire in November 2022 unless DP&L files a base distribution rate case on or before October 31, 2022, in which case the DIR will expire in November 2023. Decoupling Rider – The DRO eliminated provisions in the existing decoupling rider which allowed DP&L to recover lost revenues resulting from the implementation of energy efficiency programs and replaced it with a revenue requirement that attempts to eliminate the impacts of weather and demand on DP&L ’s revenues from residential and commercial distribution customers beginning January 1, 2019. As a result, in years with very mild weather and/or decreased demand, DP&L will be able to accrue a regulatory asset for recovery through the rider to normalize the revenues. Conversely, in periods of extreme temperatures or high demand for electricity, DP&L may record a liability for future reimbursement to customers. The rider also includes a one-time $3.7 million revenue requirement based on the increase in the number of DP&L’s residential and commercial customers from the rate case test year until September 30, 2018. Such amount was accrued and included in revenues in the third quarter of 2018 and will be collected by DP&L in 2019. TCJA – The DRO partially resolved the TCJA impacts. The new distribution rates include the impacts of the decrease in current federal income taxes beginning October 1, 2018. The DRO did not designate how much DP&L may owe for any overcollection of taxes from January 1, 2018 through September 30, 2018, nor did it resolve any decrease in future rates related to amortization of excess accumulated deferred income taxes (“ADIT”). The DRO did, however, stipulate that DP&L must refund its customers an amount no less than $4.0 million per year for the first five years of the amortization period unless all balances owed are fully returned within the first five years. For more on the impacts of the TCJA, see below. Vegetation Management Costs – The DRO authorizes DP&L to defer as a regulatory asset, with no carrying costs, annual expenses for vegetation management performed by third-party vendors. For calendar year 2018 annual expenses which are incremental to the baseline of $10.7 million can be deferred up to a $4.6 million cap. For calendar years 2019 and thereafter, annual expenses in excess of $15.7 million can be deferred up to a $4.6 million annual cap. Annual spending of less than the vegetation management baseline amounts will result in a reduction to the regulatory asset or creation of a regulatory liability. For 2018, DP&L accrued a regulatory asset for the maximum amount of $4.6 million based upon such provisions and spending above the baseline. In December 2018, DP&L filed a Distribution Modernization Plan (“DMP”) with the PUCO proposing to invest $576.0 million in capital projects over the next 10 years. There are eight principal components of DP&L’s DMP: 1) Smart Meters, 2) Self-Healing Grid, 3) Customer Engagement, 4) Enhancing Sustainability and Embracing Innovation. 5) Telecommunications, 6) Physical and Cyber Security, 7) Governance and Analytics, and 8) Grid Modernization R&D. ESP Order On March 13, 2017, DP&L filed an amended stipulation to its 2017 ESP, 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 six-year 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 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. Consistent with that settlement and the PUCO order, on January 22, 2019, DP&L filed a request to extend the DMR for the additional two years at an annual revenue amount of $199.0 million . That request is pending PUCO review; • The establishment of a non-bypassable Distribution Investment Rider to recover incremental distribution capital investments, the amount of which was established in the DP&L DRO; • 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 8 – Income Taxes and Note 10 – Equity for more information on the tax sharing payment restrictions; and • Various other riders and competitive retail market enhancements. On October 19, 2018 IGS, a retail electricity supplier, filed a Notice of Withdrawal from the amended settlement, citing a material modification by the PUCO's October 2017 order. To address the withdrawal, the PUCO established a new procedural schedule, including a hearing currently scheduled to begin April 1, 2019 . Additionally, on January 7, 2019, the Ohio Consumers' Counsel appealed the 2017 ESP Order to the Supreme Court of Ohio. That appeal is 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. On October 22, 2018, a stipulation was reached agreeing that DP&L did not exceed the SEET threshold for 2016 or 2017. That stipulation is pending PUCO approval. In future years, the SEET could have a material effect on results of operations, financial condition and cash flows. 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. Under the terms of the stipulation in the distribution rate case mentioned above, DP&L agreed to file an application at the PUCO by March 1, 2019 to refund eligible excess accumulated deferred income taxes (ADIT) and any related regulatory liability over a 10-year period. Excess ADIT related to depreciation life and method differences will be returned to customers in accordance with federal tax law and related regulations. DP&L’s rates were set using the new tax rate as a result of the distribution rate case. FERC Proceedings On May 8, 2018, DP&L filed to adjust its FERC jurisdictional transmission rates to reflect the effects of the decrease in federal income tax rates on the current portion of income tax expense as part of the TCJA, resulting in a decrease of approximately $2.4 million annually. The revised rates are in effect and all DP&L over and undercollections dating back to the March 21st effective date were settled in December 2018. On November 15, 2018 FERC issued a Notice of Proposed Rulemaking to address amortization of excess accumulated deferred income taxes resulting from the TCJA and their impact on transmission rates. Such notice requires all public utility transmission providers with stated transmission rates under an Open Access Transmission Tariff (OATT) to determine the amount of excess deferred income taxes caused by the TCJA . DP&L is unable to predict the outcome of this notice or the impact it may have on our Consolidated Financial Statements . PJM Transmission Enhancement Settlement On May 31, 2018, the FERC issued an Order on Contested Settlement regarding the cost allocation method for existing and new transmission facilities contained in the PJM Interconnection’s OATT. The FERC order approved the settlement which reduces DP&L’s transmission costs through PJM beginning in August 2018, including credits to reimburse DP&L for amounts overcharged in prior years. DP&L estimates the prior overcharge by PJM to be $41.6 million , of which approximately $14.3 million has been repaid to DP&L through December 31, 2018 and $16.5 million is classified as current in "Accounts receivable, net" and $10.8 million is classified as non-current in "Other deferred assets" on the accompanying Consolidated Balance Sheet. All of the transmission charges and credits impacted by this FERC order are items that are included for full recovery in DP&L’s nonbypassable TCRR. Accordingly, DP&L has also established offsetting regulatory liabilities. While this development will have a temporary cash flow benefit to DP&L , there is no impact to operating income or net income as all credits will be passed to DP&L’s customers through the TCRR, which began in November 2018. Regulatory Assets and Liabilities In accordance with FASC 980, we have recognized total regulatory assets of $193.7 million and $187.1 million at December 31, 2018 and 2017 , respectively, and total regulatory liabilities of $313.2 million and $236.0 million at December 31, 2018 and 2017 , 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 2018 2017 Regulatory assets, current: Undercollections to be collected through rate riders A/B 2019 $ 40.5 $ 23.9 Rate case expenses being recovered in base rates B 2019 0.6 — Total regulatory assets, current 41.1 23.9 Regulatory assets, non-current: Pension benefits B Ongoing 87.5 92.4 Unrecovered OVEC charges C Undetermined 28.7 27.8 Fuel costs B 2020 3.3 9.3 Regulatory compliance costs B 2020 6.1 9.2 Smart grid and AMI costs B Undetermined 8.5 7.3 Unamortized loss on reacquired debt B Various 6.0 7.0 Deferred storm costs A Undetermined 4.7 2.1 Deferred vegetation management and other A/B Undetermined 7.8 8.1 Total regulatory assets, non-current 152.6 163.2 Total regulatory assets $ 193.7 $ 187.1 Regulatory liabilities, current: Overcollection of costs to be refunded through rate riders A/B 2019 $ 34.9 $ 14.8 Total regulatory liabilities, current 34.9 14.8 Regulatory liabilities, non-current: Estimated costs of removal - regulated property Not Applicable 139.1 132.8 Deferred income taxes payable through rates Various 116.3 83.4 PJM transmission enhancement settlement A 2025 16.9 — Postretirement benefits B Ongoing 6.0 5.0 Total regulatory liabilities, non-current 278.3 221.2 Total regulatory liabilities $ 313.2 $ 236.0 A – Recovery of incurred costs plus rate of return. B – Recovery of incurred costs without a rate of return. C – 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 net return on $5.5 million of this net deferral. These items include undercollection of: (i) Distribution Modernization Rider revenues, (ii) decoupling rider (see above), (iii) uncollectible rider and (iv) energy efficiency rider. 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, (v) certain transmission related costs including current portion of PJM transmission enhancement settlement (see above) and (vi) reconciliation 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 rider represents 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. These costs are being recovered over a three-year period. Rate case costs represents costs associated with preparing a distribution rate case. DP&L was granted recovery of these costs which do not earn a return, as part of the DRO. 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. DP&L requested recovery of these costs as part of the December 2018 DMP filing with the PUCO described earlier. 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 2017 and 2018. 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 plans to file petitions seeking recovery of each calendar year of storm costs in the following calendar year. Recovery of these costs is probable by 2020, 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 through rates represent deferred income tax liabilities 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. 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 its 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, this liability reflects the estimated deferred taxes DP&L expects to return to customers in future periods. 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. |
Subsidiaries [Member] | |
Schedule of Regulatory Assets and Liabilities [Text Block] | Regulatory Matters Distribution Rate Order On September 26, 2018 the PUCO issued the DRO establishing new base distribution rates for DP&L , which became effective October 1, 2018. The DRO approved, without modification, a stipulation and recommendation previously filed by DP&L , along with various intervening parties and the PUCO staff. The DRO established a revenue requirement of $248.0 million for DP&L 's electric service base distribution rates which reflects an increase to distribution revenues of approximately $29.8 million per year. In addition to the increase in base distribution rates, and among other matters, the DRO provides for a return on equity of 9.999% and a cost of long-term debt of 4.8% and for the following items: DIR – The DRO authorized DP&L to begin charging a Distribution Investment Rider ("DIR") set initially at $12.2 million annually, effective October 1, 2018. The DIR revenue requirement shall be updated quarterly and will increase as DP&L makes qualified investments in its distribution network, subject to annual revenue limits which increase each year; the revenue limit for 2019 is $22.0 million . The DIR will expire in November 2022 unless DP&L files a base distribution rate case on or before October 31, 2022, in which case the DIR will expire in November 2023. Decoupling Rider – The DRO eliminated provisions in the existing decoupling rider which allowed DP&L to recover lost revenues resulting from the implementation of energy efficiency programs and replaced it with a revenue requirement that attempts to eliminate the impacts of weather and demand on DP&L ’s revenues from residential and commercial distribution customers beginning January 1, 2019. As a result, in years with very mild weather and/or decreased demand, DP&L will be able to accrue a regulatory asset for recovery through the rider to normalize the revenues. Conversely, in periods of extreme temperatures or high demand for electricity, DP&L may record a liability for future reimbursement to customers. The rider also includes a one-time $3.7 million revenue requirement based on the increase in the number of DP&L’s residential and commercial customers from the rate case test year until September 30, 2018. Such amount was accrued and included in revenues in the third quarter of 2018 and will be collected by DP&L in 2019. TCJA – The DRO partially resolved the TCJA impacts. The new distribution rates include the impacts of the decrease in current federal income taxes beginning October 1, 2018. The DRO did not designate how much DP&L may owe for any overcollection of taxes from January 1, 2018 through September 30, 2018, nor did it resolve any decrease in future rates related to amortization of excess accumulated deferred income taxes (“ADIT”). The DRO did, however, stipulate that DP&L must refund its customers an amount no less than $4.0 million per year for the first five years of the amortization period unless all balances owed are fully returned within the first five years. For more on the impacts of the TCJA, see below. Vegetation Management Costs – The DRO authorizes DP&L to defer as a regulatory asset, with no carrying costs, annual expenses for vegetation management performed by third-party vendors. For calendar year 2018 annual expenses which are incremental to the baseline of $10.7 million can be deferred up to a $4.6 million cap. For calendar years 2019 and thereafter, annual expenses in excess of $15.7 million can be deferred up to a $4.6 million annual cap. Annual spending of less than the vegetation management baseline amounts will result in a reduction to the regulatory asset or creation of a regulatory liability. For 2018, DP&L accrued a regulatory asset for the maximum amount of $4.6 million based upon such provisions and spending above the baseline. In December 2018, DP&L filed a Distribution Modernization Plan (“DMP”) with the PUCO proposing to invest $576.0 million in capital projects over the next 10 years. There are eight principal components of DP&L’s DMP: 1) Smart Meters, 2) Self-Healing Grid, 3) Customer Engagement, 4) Enhancing Sustainability and Embracing Innovation. 5) Telecommunications, 6) Physical and Cyber Security, 7) Governance and Analytics, and 8) Grid Modernization R&D. ESP Order On March 13, 2017, DP&L filed an amended stipulation to its 2017 ESP, 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 six-year 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 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. Consistent with that settlement and the PUCO order, on January 22, 2019, DP&L filed a request to extend the DMR for the additional two years at an annual revenue amount of $199.0 million . That request is pending PUCO review; • The establishment of a non-bypassable Distribution Investment Rider to recover incremental distribution capital investments, the amount of which was established in the DP&L DRO; • 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 8 – Income Taxes and Note 10 – Equity for more information on the tax sharing payment restrictions; and • Various other riders and competitive retail market enhancements. On October 19, 2018 IGS, a retail electricity supplier, filed a Notice of Withdrawal from the amended settlement, citing a material modification by the PUCO's October 2017 order. To address the withdrawal, the PUCO established a new procedural schedule, including a hearing currently scheduled to begin April 1, 2019 . Additionally, on January 7, 2019, the Ohio Consumers' Counsel appealed the 2017 ESP Order to the Supreme Court of Ohio. That appeal is 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. On October 22, 2018, a stipulation was reached agreeing that DP&L did not exceed the SEET threshold for 2016 or 2017. That stipulation is pending PUCO approval. In future years, the SEET could have a material effect on results of operations, financial condition and cash flows. 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. Under the terms of the stipulation in the distribution rate case mentioned above, DP&L agreed to file an application at the PUCO by March 1, 2019 to refund eligible excess accumulated deferred income taxes (ADIT) and any related regulatory liability over a 10-year period. Excess ADIT related to depreciation life and method differences will be returned to customers in accordance with federal tax law and related regulations. DP&L’s rates were set using the new tax rate as a result of the distribution rate case. FERC Proceedings On May 8, 2018, DP&L filed to adjust its FERC jurisdictional transmission rates to reflect the effects of the decrease in federal income tax rates on the current portion of income tax expense as part of the TCJA, resulting in a decrease of approximately $2.4 million annually. The revised rates are in effect and all DP&L over and undercollections dating back to the March 21st effective date were settled in December 2018. On November 15, 2018 FERC issued a Notice of Proposed Rulemaking to address amortization of excess accumulated deferred income taxes resulting from the TCJA and their impact on transmission rates. Such notice requires all public utility transmission providers with stated transmission rates under an Open Access Transmission Tariff (OATT) to determine the amount of excess deferred income taxes caused by the TCJA . DP&L is unable to predict the outcome of this notice or the impact it may have on our Financial Statements PJM Transmission Enhancement Settlement On May 31, 2018, the FERC issued an Order on Contested Settlement regarding the cost allocation method for existing and new transmission facilities contained in the PJM Interconnection’s OATT. The FERC order approved the settlement which reduces DP&L’s transmission costs through PJM beginning in August 2018, including credits to reimburse DP&L for amounts overcharged in prior years. DP&L estimates the prior overcharge by PJM to be $41.6 million , of which approximately $14.3 million has been repaid to DP&L through December 31, 2018 and $16.5 million is classified as current in "Accounts receivable, net" and $10.8 million is classified as non-current in "Other deferred assets" on the accompanying Balance Sheet. All of the transmission charges and credits impacted by this FERC order are items that are included for full recovery in DP&L’s nonbypassable TCRR. Accordingly, DP&L has also established offsetting regulatory liabilities. While this development will have a temporary cash flow benefit to DP&L , there is no impact to operating income or net income as all credits will be passed to DP&L’s customers through the TCRR, which began in November 2018. Regulatory Assets and Liabilities In accordance with FASC 980, we have recognized total regulatory assets of $193.7 million and $187.1 million at December 31, 2018 and 2017 , respectively, and total regulatory liabilities of $313.2 million and $236.0 million at December 31, 2018 and 2017 , 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 2018 2017 Regulatory assets, current: Undercollections to be collected through rate riders A/B 2019 $ 40.5 $ 23.9 Rate case expenses being recovered in base rates B 2019 0.6 — Total regulatory assets, current 41.1 23.9 Regulatory assets, non-current: Pension benefits B Ongoing 87.5 92.4 Unrecovered OVEC charges C Undetermined 28.7 27.8 Fuel costs B 2020 3.3 9.3 Regulatory compliance costs B 2020 6.1 9.2 Smart grid and AMI costs B Undetermined 8.5 7.3 Unamortized loss on reacquired debt B Various 6.0 7.0 Deferred storm costs A Undetermined 4.7 2.1 Deferred vegetation management and other A/B Undetermined 7.8 8.1 Total regulatory assets, non-current 152.6 163.2 Total regulatory assets $ 193.7 $ 187.1 Regulatory liabilities, current: Overcollection of costs to be refunded through rate riders A/B 2018 $ 34.9 $ 14.8 Total regulatory liabilities, current 34.9 14.8 Regulatory liabilities, non-current: Estimated costs of removal - regulated property Not Applicable 139.1 132.8 Deferred income taxes payable through rates Various 116.3 83.4 PJM transmission enhancement settlement A 2025 16.9 — Postretirement benefits B Ongoing 6.0 5.0 Total regulatory liabilities, non-current 278.3 221.2 Total regulatory liabilities $ 313.2 $ 236.0 A – Recovery of incurred costs plus rate of return. B – Recovery of incurred costs without a rate of return. C – 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 net return on $5.5 million of this net deferral. These items include undercollection of: (i) Distribution Modernization Rider revenues, (ii) decoupling rider (see above), (iii) uncollectible rider and (iv) energy efficiency rider. 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, (v) certain transmission related costs including current portion of PJM transmission enhancement settlement (see above) and (vi) reconciliation 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 rider represents 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. These costs are being recovered over a three-year period. Rate case costs represents costs associated with preparing a distribution rate case. DP&L was granted recovery of these costs which do not earn a return, as part of the DRO. 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. DP&L requested recovery of these costs as part of the December 2018 DMP filing with the PUCO described earlier. 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 2017 and 2018. 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 plans to file petitions seeking recovery of each calendar year of storm costs in the following calendar year. Recovery of these costs is probable by 2020, 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 through rates represent deferred income tax liabilities 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. 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 its 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, this liability reflects the estimated deferred taxes DP&L expects to return to customers in future periods. 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, 2018 | |
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, 2018 and 2017 : December 31, 2018 December 31, 2017 $ in millions Composite Rate Composite Rate (a) Regulated: Transmission $ 223.2 4.1% $ 242.7 4.0% Distribution 1,289.8 4.5% 1,197.5 4.9% General 13.2 8.5% 13.7 7.1% Non-depreciable 60.4 N/A 64.7 N/A Total regulated 1,586.6 1,518.6 Unregulated: Production / Generation — N/A 0.2 N/A Other 21.2 6.7% 21.1 7.0% Non-depreciable 7.8 N/A 4.2 N/A Total unregulated 29.0 25.5 Total property, plant and equipment in service $ 1,615.6 4.3% $ 1,544.1 5.0% (a) Composite rates for 2017 include property classified in non-current assets of discontinued operations and held-for-sale businesses. In June 2018, DP&L closed on a transmission asset transaction with Duke and AEP, where ownership stakes in certain previously co-owned transmission assets were exchanged to eliminate co-ownership. Each previously co-owned transmission asset became wholly-owned by one of DP&L , Duke or AEP after the transaction. This transaction also resulted in cash proceeds to DP&L of $10.6 million and no gain or loss was recorded on the transaction . 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 related to Conesville, the closed Hutchings EGU, and the previously owned Beckjord Facility are recorded within Asset retirement obligations on the consolidated balance sheets. The generation AROs related to our other retired or sold generation facilities are recorded in Non-current liabilities of discontinued operations and held-for-sale businesses on the consolidated balance sheets and are excluded from the table below. See Note 15 – Discontinued Operations for additional information. 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 AROs $ in millions Balance at December 31, 2016 $ 15.0 Calendar 2017 Revisions to cash flow and timing estimates (0.1 ) Accretion expense 0.4 Settlements (0.2 ) Balance at December 31, 2017 15.1 Calendar 2018 Revisions to cash flow and timing estimates (2.6 ) Accretion expense 0.3 Settlements (a) (3.4 ) Balance at December 31, 2018 $ 9.4 (a) Primarily includes settlement related to transfer of Beckjord Facility. See Note 16 – Dispositions for additional information. See Note 5 – Fair Value for further discussion on ARO revisions to cash flow and timing estimates. 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 $139.1 million and $132.8 million in estimated costs of removal at December 31, 2018 and 2017 , 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, 2016 $ 126.5 Calendar 2017 Additions 12.0 Settlements (5.7 ) Balance at December 31, 2017 132.8 Calendar 2018 Additions 14.3 Settlements (8.0 ) Balance at December 31, 2018 $ 139.1 |
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, 2018 and 2017 : December 31, 2018 December 31, 2017 $ in millions Composite Rate Composite Rate (a) Regulated: Transmission $ 386.7 2.4% $ 414.6 2.4% Distribution 1,796.4 3.2% 1,735.9 3.4% General 30.9 3.6% 31.2 3.1% Non-depreciable 60.4 N/A 64.6 N/A Total regulated 2,274.4 2,246.3 Unregulated: Other — N/A 0.2 2.7% Non-depreciable — N/A 0.7 N/A Total unregulated — 0.9 Total property, plant and equipment in service $ 2,274.4 3.0% $ 2,247.2 3.4% In June 2018, DP&L closed on a transmission asset transaction with Duke and AEP, where ownership stakes in certain previously co-owned transmission assets were exchanged to eliminate co-ownership. Each previously co-owned transmission asset became wholly-owned by one of DP&L , Duke or AEP after the transaction. This transaction also resulted in cash proceeds to DP&L of $10.6 million . 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. The DP&L AROs are for our retired Hutchings EGU and relate primarily to asbestos removal. 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, 2016 $ 8.2 Calendar 2017 Accretion expense 0.1 Settlements (0.3 ) Balance at December 31, 2017 8.0 Calendar 2018 Settlements (a) (3.3 ) Balance at December 31, 2018 $ 4.7 (a) Primarily includes settlement related to transfer of Beckjord Facility. See Note 15 – Dispositions for additional information. See Note 5 – Fair Value for further discussion on ARO fair value measurements. 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 $139.1 million and $132.8 million in estimated costs of removal at December 31, 2018 and 2017 , 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, 2016 $ 126.5 Calendar 2017 Additions 12.0 Settlements (5.7 ) Balance at December 31, 2017 132.8 Calendar 2018 Additions 14.3 Settlements (8.0 ) Balance at December 31, 2018 $ 139.1 |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2018 | |
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, 2018 and 2017 . See Note 6 – Derivative Instruments and Hedging Activities for the fair values of our derivative instruments. December 31, 2018 December 31, 2017 $ in millions Cost Fair Value Cost Fair Value Assets Money market funds $ 0.4 $ 0.4 $ 0.3 $ 0.3 Equity securities 2.4 3.5 2.5 4.2 Debt securities 4.1 4.0 4.3 4.3 Hedge funds 0.1 0.1 0.1 0.2 Tangible assets 0.1 0.1 0.1 0.1 Total assets $ 7.1 $ 8.1 $ 7.3 $ 9.1 Carrying Value Fair Value Carrying Value Fair Value Liabilities Long-term debt $ 1,475.9 $ 1,519.6 $ 1,704.8 $ 1,819.3 Fair Value Hierarchy Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. These inputs are then categorized as: • Level 1 (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 among Level 1, Level 2 or Level 3 of the fair value hierarchy during the years ended December 31, 2018 and 2017 . 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 and these assets are not used for general operating purposes. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” was effective as of January 1, 2018. This ASU requires the change in the fair value of equity instruments to be recorded in income rather than in OCI. Equity Instruments were defined to include all mutual funds, regardless of the underlying investments. Therefore, as of January 1, 2018, AOCI of $1.6 million ( $1.0 million net of tax) was reversed to Accumulated Deficit and all future changes to fair value on the Master Trust Assets will be included in income in the period that the changes occur. These changes to fair value were not material for the year ended December 31, 2018. 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 consolidated balance sheets and classified as available for sale. During the year ended December 31, 2018 , $0.5 million ( $0.4 million after tax) of various investments were sold to facilitate the distribution of benefits. The fair value of assets and liabilities at December 31, 2018 and 2017 and the respective category within the fair value hierarchy for DPL was determined as follows: $ in millions Fair Value at December 31, 2018 (a) Fair Value at December 31, 2017 (a) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets Master trust assets Money market funds $ 0.4 $ — $ — $ 0.4 $ 0.3 $ — $ — $ 0.3 Equity securities — 3.5 — 3.5 — 4.2 — 4.2 Debt securities — 4.0 — 4.0 — 4.3 — 4.3 Hedge funds — 0.1 — 0.1 — 0.2 — 0.2 Tangible assets — 0.1 — 0.1 — 0.1 — 0.1 Total Master trust assets 0.4 7.7 — 8.1 0.3 8.8 — 9.1 Derivative assets Interest rate hedge — 1.5 — 1.5 — 1.5 — 1.5 Total Derivative assets — 1.5 — 1.5 — 1.5 — 1.5 Total assets $ 0.4 $ 9.2 $ — $ 9.6 $ 0.3 $ 10.3 $ — $ 10.6 Liabilities Long-term debt $ — $ 1,501.9 $ 17.7 $ 1,519.6 $ — $ 1,801.5 $ 17.8 $ 1,819.3 Total liabilities $ — $ 1,501.9 $ 17.7 $ 1,519.6 $ — $ 1,801.5 $ 17.8 $ 1,819.3 (a) Includes credit valuation adjustment Our financial instruments are valued using the market approach in the following categories: • Level 1 inputs are used 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 interest rate hedge contracts which are valued using a benchmark interest rate. 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 certain debt balances are considered a Level 3 input because the notes are not publicly traded. Our long-term debt is fair valued for disclosure purposes only. All 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. In 2018, DPL recorded a net reduction to its ARO liability for Conesville's ash pond and landfill of $2.6 million to reflect revisions to cash flow and timing estimates. The balance of AROs was $9.4 million and $15.1 million at December 31, 2018 and 2017 , respectively, which excludes AROs associated with our discontinued operations. See Note 15 – Discontinued Operations for additional information on AROs associated with our discontinued operations. When evaluating impairment of long-lived assets, we measure fair value using the applicable fair value measurement guidance. Impairment expense is measured by comparing the fair value at the evaluation date to the carrying amount. The following table summarizes major categories of assets 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 (b) Level 1 Level 2 Level 3 Loss Long-lived assets (a) Year ended December 31, 2016 Conesville December 31, 2016 $ 25.0 $ — $ — $ 1.1 23.9 (a) See Note 17 – Fixed-asset Impairments for further information (b) 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, 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 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 |
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, 2018 and 2017 . See also Note 6 – Derivative Instruments and Hedging Activities for the fair values of our derivative instruments. December 31, 2018 December 31, 2017 $ in millions Cost Fair Value Cost Fair Value Assets Money market funds $ 0.4 $ 0.4 $ 0.3 $ 0.3 Equity securities 2.4 3.5 2.5 4.2 Debt securities 4.1 4.0 4.3 4.3 Hedge funds 0.1 0.1 0.1 0.2 Tangible assets 0.1 0.1 0.1 0.1 Total assets $ 7.1 $ 8.1 $ 7.3 $ 9.1 Carrying Value Fair Value Carrying Value Fair Value Liabilities Long-term debt $ 586.1 $ 593.8 $ 646.6 $ 658.4 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 among Level 1, Level 2 or Level 3 of the fair value hierarchy during the years ended December 31, 2018 and 2017 . 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 and these assets are not used for general operating purposes. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” was effective as of January 1, 2018. This ASU requires the change in the fair value of equity instruments to be recorded in income rather than in OCI. Equity Instruments were defined to include all mutual funds, regardless of the underlying investments. Therefore, as of January 1, 2018, AOCI of $1.7 million ( $1.1 million net of tax) was reversed to Accumulated Deficit and all future changes to fair value on the Master Trust Assets will be included in income in the period that the changes occur. These changes to fair value were not material for the year ended December 31, 2018. 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 consolidated balance sheets and classified as available for sale. During the year ended December 31, 2018 , $0.5 million ( $0.4 million after tax) of various investments were sold to facilitate the distribution of benefits. The fair value of assets and liabilities at December 31, 2018 and 2017 and the respective category within the fair value hierarchy for DP&L was determined as follows: $ in millions Fair Value at December 31, 2018 (a) Fair Value at December 31, 2017 (a) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets Master trust assets Money market funds $ 0.4 $ — $ — $ 0.4 $ 0.3 $ — $ — $ 0.3 Equity securities — 3.5 — 3.5 — 4.2 — 4.2 Debt securities — 4.0 — 4.0 — 4.3 — 4.3 Hedge funds — 0.1 — 0.1 — 0.2 — 0.2 Tangible assets — 0.1 — 0.1 — 0.1 — 0.1 Total Master trust assets 0.4 7.7 — 8.1 0.3 8.8 — 9.1 Derivative assets Interest rate hedges — 1.5 — 1.5 — 1.5 — 1.5 Total derivative assets — 1.5 — 1.5 — 1.5 — 1.5 Total assets $ 0.4 $ 9.2 $ — $ 9.6 $ 0.3 $ 10.3 $ — $ 10.6 Liabilities Long-term debt $ — $ 576.1 $ 17.7 $ 593.8 $ — $ 640.6 $ 17.8 658.4 Total liabilities $ — $ 576.1 $ 17.7 $ 593.8 $ — $ 640.6 $ 17.8 $ 658.4 (a) Includes credit valuation adjustment Our financial instruments are valued using the market approach in the following categories: • Level 1 inputs are used 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 interest rate hedge contracts which are valued using a benchmark interest rate. 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 certain debt balances are considered a Level 3 input because the notes are not publicly traded. Our long-term debt is fair valued for disclosure purposes only. All 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. The balance of AROs was $4.7 million and $8.0 million at December 31, 2018 and 2017 , respectively. |
Derivative Instruments and Hedg
Derivative Instruments and Hedging Activities | 12 Months Ended |
Dec. 31, 2018 | |
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 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. 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, 2018 , DPL's outstanding derivative instruments were as follows: Commodity Accounting Treatment (a) Unit Purchases Sales Net Purchases/ (Sales) Interest Rate Swaps Designated USD $ 140,000.0 $ — $ 140,000.0 (a) Refers to whether the derivative instruments have been designated as a cash flow hedge. At December 31, 2017 , DPL's outstanding derivative instruments were as follows: Commodity Accounting Treatment (a) Unit Purchases Sales Net Purchases/ (Sales) FTRs (b) Not designated MWh 2.1 — 2.1 Natural Gas (b) Not designated Dths 3,322.5 (390.0 ) 2,932.5 Forward Power Contracts (b) Designated MWh 678.5 (1,667.0 ) (988.5 ) Forward Power Contracts (b) 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. (b) As of December 31, 2017, the related asset and liability balances for these derivative instruments were classified in assets and liabilities of discontinued operations and held-for-sale businesses. 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. With the adoption of ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted improvements to Accounting for Hedging Activities effective January 1, 2019, we will no longer be required to calculate effectiveness and thus 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 in the period in which it settles. In prior years, we entered 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. As of December 31, 2018, we no longer held any positions in forward power contracts or forward natural gas contracts. We have two interest rate swaps to hedge the variable interest on our $140.0 million variable interest rate tax-exempt First Mortgage Bonds. The interest rate swaps have a combined notional amount of $140.0 million and will settle monthly based on a one-month LIBOR. As of December 31, 2017, the interest rate swaps had a combined notional amount of $200.0 million . On March 29, 2018, we settled $60.0 million of these interest rate swaps due to the partial repayment of the underlying debt and a gain of $0.8 million was recorded as a reduction to interest expense. Since the swap was partially settled, the remaining swaps were de-designated and then re-designated with a new hypothetical derivative. The AOCI associated with the remaining swaps will be amortized out of AOCI into interest expense over the remaining life of the underlying debt. 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, 2018 2017 2016 $ in millions (net of tax) Power Interest Rate Power Interest Rate Power Interest Rate Beginning accumulated derivative gain / (loss) in AOCI $ (2.8 ) $ 17.5 $ (4.3 ) $ 17.4 $ 9.2 $ 17.5 Net gains / (losses) associated with current period hedging transactions — (0.1 ) 8.8 0.8 15.7 0.4 Net gains / (losses) reclassified to earnings: Interest Expense — (0.8 ) — (0.7 ) — (0.5 ) Income / (loss) from discontinued operations before income tax 3.2 — (7.3 ) — (29.2 ) — Ending accumulated derivative gain / (loss) in AOCI $ 0.4 $ 16.6 $ (2.8 ) $ 17.5 $ (4.3 ) $ 17.4 Portion expected to be reclassified to earnings in the next twelve months (a) $ — $ (0.8 ) Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) 0 20 (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 In prior years certain derivative contracts were entered into on a regular basis as part of our risk management program but did not qualify for hedge accounting or the normal purchases and sales exceptions under FASC 815. Accordingly, such contracts were 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 entered into as part of our risk management program may have been settled financially, by physical delivery or net settled with the counterparty. We marked to market FTRs, natural gas futures and certain forward power contracts. For the years ended December 31, 2018, 2017, and 2016, all amounts related to such contracts are presented in discontinued operations. As of December 31, 2018, we no longer have any such contracts. Certain qualifying derivative instruments we previously held were 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. For the years ended December 31, 2018, 2017, and 2016, all amounts related to such contracts are presented in discontinued operations. As of December 31, 2018, we no longer have any such contracts. 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, 2018 , 2017 and 2016 : Year ended December 31, 2018 $ in millions FTRs Power Natural Gas Total Change in unrealized gain / (loss) $ 0.3 $ — $ (0.1 ) $ 0.2 Realized gain / (loss) 0.4 — 0.3 0.7 Total $ 0.7 $ — $ 0.2 $ 0.9 Recorded in Statement of Operations: gain / (loss) Income / (loss) from discontinued operations before income tax $ 0.7 $ — $ 0.2 $ 0.9 Total $ 0.7 $ — $ 0.2 $ 0.9 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 in Statement of Operations: gain / (loss) Income / (loss) from discontinued operations before income tax $ 0.4 $ 1.2 $ 1.6 $ 3.2 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 in Statement of Operations: gain / (loss) Income / (loss) from discontinued operations before income tax $ (0.3 ) $ (3.2 ) $ 2.6 $ (0.9 ) Total $ (0.3 ) $ (3.2 ) $ 2.6 $ (0.9 ) 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, 2018 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 prepayments and current assets) Interest Rate Swaps Designated $ 0.9 $ — $ — $ 0.9 Long-term derivative positions (presented in Other deferred assets) Interest Rate Swaps Designated 0.6 — — 0.6 Total assets $ 1.5 $ — $ — $ 1.5 (a) Includes credit valuation adjustment. 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 Current assets of discontinued operations and held-for-sale businesses) Forward power contracts Designated $ 4.9 $ (4.9 ) $ — $ — Forward power contracts Not designated 5.3 (3.7 ) — 1.6 FTRs Not designated 0.2 (0.1 ) — 0.1 Long-term derivative positions (presented in Other deferred assets) Interest rate swaps Designated 1.5 — — 1.5 Long-term derivative positions (presented in Non-current assets of discontinued operations and held-for-sale businesses) Forward power contracts Not designated 0.6 — — 0.6 Total assets $ 12.5 $ (8.7 ) $ — $ 3.8 Liabilities Short-term derivative positions (presented in Current liabilities of discontinued operations and held-for-sale businesses) 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. |
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 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. 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, 2018 and 2017 , the principal balance of the interest rate hedges was $140.0 million and $200.0 million , respectively. 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. With the adoption of ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted improvements to Accounting for Hedging Activities effective January 1, 2019, we will no longer be required to calculate effectiveness and thus 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 in the period in which it settles. We have two interest rate swaps to hedge the variable interest on our $140.0 million variable interest rate tax-exempt First Mortgage Bonds. The interest rate swaps have a combined notional amount of $140.0 million and will settle monthly based on a one-month LIBOR. As of December 31, 2017, the interest rate swaps had a combined notional amount of $200.0 million . On March 29, 2018, we settled $60.0 million of these interest rate swaps due to the partial repayment of the underlying debt and a gain of $0.8 million was recorded as a reduction to interest expense. Since the swap was partially settled, the remaining swaps were de-designated and then re-designated with a new hypothetical derivative. The AOCI associated with the remaining swaps will be amortized out of AOCI into interest expense over the remaining life of the underlying debt. 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, 2018 2017 2016 $ in millions (net of tax) Interest Rate Power Interest Rate Power Interest Rate Beginning accumulated derivative gain / (loss) in AOCI $ 1.4 $ (4.3 ) $ 1.6 $ 9.2 $ 2.0 Net gains / (losses) associated with current period hedging transactions (0.1 ) 11.9 0.5 15.7 0.4 Net gains / (losses) reclassified to earnings: Interest expense (0.7 ) — (0.7 ) — (0.8 ) Loss from discontinued operations — (5.5 ) — (29.2 ) — Transfer of generation assets to subsidiary of parent — (2.1 ) — — — Ending accumulated derivative gain / (loss) in AOCI $ 0.6 $ — $ 1.4 $ (4.3 ) $ 1.6 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) 20 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 2018 2017 Interest rate hedges in a Current asset position Cash Flow Hedge Other prepayments and current assets Gross Fair Value as presented in the Balance Sheets $ 0.9 $ — Interest rate hedges in a non-current asset position Cash Flow Hedge Other deferred assets Gross Fair Value as presented in the Balance Sheets $ 0.6 $ 1.5 |
Debt
Debt | 12 Months Ended |
Dec. 31, 2018 | |
Debt Instrument [Line Items] | |
Debt | Long-term debt Long-term debt $ in millions Interest Rate Maturity December 31, 2018 December 31, 2017 Term loan - rates from: 3.57% - 4.82% (a) and 4.00% - 4.60% (b) 2022 $ 436.1 $ 440.6 Tax-exempt First Mortgage Bonds - rates from: 2.49% - 2.93% (a) and 1.29% - 1.42% (b) 2020 140.0 200.0 U.S. Government note 4.2% 2061 17.7 17.8 Unamortized deferred financing costs (6.3 ) (9.8 ) Unamortized debt discounts and premiums, net (1.4 ) (2.0 ) Total long-term debt at subsidiary 586.1 646.6 Bank term loan - rates from: 3.02% - 4.10% (a) and 2.67% - 3.02% (b) 2020 — 70.0 Senior unsecured bonds 6.75% 2019 99.0 200.0 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 (4.3 ) (6.8 ) Unamortized debt discounts and premiums, net (0.5 ) (0.6 ) Total long-term debt 1,475.9 1,704.8 Less: current portion (103.6 ) (4.6 ) Long-term debt, net of current portion $ 1,372.3 $ 1,700.2 (a) Range of interest rates for the year ended December 31, 2018 . (b) Range of interest rates for the year ended December 31, 2017 . (c) Note payable to related party. See Note 12 – Related Party Transactions for additional information. At December 31, 2018 , maturities of long-term debt are summarized as follows: Due during the years ending December 31, $ in millions 2019 $ 103.6 2020 144.7 2021 784.7 2022 422.8 2023 0.2 Thereafter 32.4 1,488.4 Unamortized discounts and premiums, net (1.9 ) Deferred financing costs, net (10.6 ) Total long-term debt $ 1,475.9 Premiums or discounts recognized at the Merger date are amortized over the life of the debt using the effective interest method. Significant Transactions On March 30, 2018, DPL issued a Notice of Partial Redemption to the Trustee (U.S. Bank) on the DPL 6.75% Senior Notes due 2019. DPL notified the trustee that it was calling $101.0 million of the $200.0 million outstanding principal amount of these notes. These bonds were redeemed at par plus accrued interest and a make-whole premium of $5.1 million on April 30, 2018 with cash on hand. On March 30, 2018, DP&L commenced a redemption of $60.0 million of outstanding tax exempt First Mortgage Bonds due 2020 at par value (plus accrued and unpaid interest). These bonds were redeemed at par plus accrued interest on April 30, 2018 with cash on hand. On March 27, 2018, DPL made a $70.0 million prepayment to eliminate the outstanding balance of its bank term loan in full. As of March 31, 2018, the term loan was fully paid off. 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. There were no such transactions prior to July 3, 2018. Debt Covenants and Restrictions 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 ratio in the agreements is not to exceed 7.25 to 1.00 for any fiscal quarter ending September 30, 2015 through December 31, 2018; it then steps down to not exceed 7.00 to 1.00 for any fiscal quarter ending January 1, 2019 through June 30, 2019; and it then steps down not to exceed 6.75 to 1.00 for any fiscal quarter ending July 1, 2019 through December 31, 2019; and it then steps down not to exceed 6.50 to 1.00 for any fiscal quarter ending January 1, 2020 and afterward. As of December 31, 2018 , this financial covenant was met with a ratio of 5.84 to 1.00. 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. The ratio, per the agreement, is to be not less than 2.10 to 1.00 for any fiscal quarter ending September 30, 2015 through December 31, 2018; it then steps up to be not less than 2.25 to 1.00 for any fiscal quarter ending January 1, 2019 and afterward. As of December 31, 2018, this financial covenant was met with a ratio of 2.61 to 1.00. DPL’s secured revolving credit agreement and senior unsecured notes due 2019 also restricts 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, (i) 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, (ii) DPL’s senior long-term debt rating from two of the three major credit rating agencies is at least investment grade. As of December 31, 2018, DPL's senior-long term debt rating was at least investment grade by two of the three major credit rating agencies. However, 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. On January 22, 2019, DP&L filed a request to extend the DMR for an additional two years. See Note 3 – Regulatory Matters for more information. As a result, as of December 31, 2018, DPL was prohibited under this order from making a distribution to its shareholder or making a loan to any of its affiliates (other than its subsidiaries). 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) 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. DP&L’s Total Debt to Total Capitalization ratio shall not be greater than 0.65 to 1.00; except that, the ratio shall be suspended if DP&L’s long-term indebtedness is less than or equal to $750.0 million . Additionally, the ratio shall be suspended 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 of December 31, 2018, DP&L's ratings meet those requirements and this ratio is suspended for the quarter ended December 31, 2018. The second financial covenant measures EBITDA to Interest Expense. The Total Consolidated EBITDA to Consolidated Interest Charges 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. The ratio, per the agreement, is to be not less than 2.50 to 1.00. This covenant was met with a ratio of 8.09 to 1.00 as of December 31, 2018. DP&L does not have any meaningful restrictions in its debt financing documents prohibiting dividends to its parent, DPL. As of December 31, 2018 , 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 | Long-term debt Long-term debt is as follows: Long-term debt $ in millions Interest Rate Maturity December 31, 2018 December 31, 2017 Term loan - rates from: 3.57% - 4.82% (a) and 4.00% - 4.60% (b) 2022 $ 436.1 $ 440.6 Tax-exempt First Mortgage Bonds - rates from: 2.49% - 2.93% (a) and 1.29% - 1.42% (b) 2020 140.0 200.0 U.S. Government note 4.2% 2061 17.7 17.8 Unamortized deferred financing costs (6.3 ) (9.8 ) Unamortized debt discount (1.4 ) (2.0 ) Total long-term debt 586.1 646.6 Less: current portion (4.6 ) (4.6 ) Long-term debt, net of current portion $ 581.5 $ 642.0 (a) Range of interest rates for the year ended December 31, 2018 . (b) Range of interest rates for the year ended December 31, 2017 . At December 31, 2018 , maturities of long-term debt are summarized as follows: Due during the years ending December 31, $ in millions 2019 $ 4.6 2020 144.7 2021 4.7 2022 422.8 2023 0.2 Thereafter 16.8 593.8 Unamortized discounts and premiums, net (1.4 ) Deferred financing costs, net (6.3 ) Total long-term debt $ 586.1 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. There were no such transactions prior to July 3, 2018. On March 30, 2018, DP&L commenced a redemption of $60.0 million of outstanding tax exempt First Mortgage Bonds due 2020 at par value (plus accrued and unpaid interest). These bonds were redeemed at par plus accrued interest on April 30, 2018 with cash on hand. 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) 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. DP&L’s Total Debt to Total Capitalization ratio shall not be greater than 0.65 to 1.00; except that, the ratio shall be suspended if DP&L’s long-term indebtedness is less than or equal to $750.0 million . Additionally, the ratio shall be suspended 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 of December 31, 2018, DP&L's ratings meet those requirements and this ratio is suspended for the quarter ended December 31, 2018. The second financial covenant measures EBITDA to Interest Expense. The Total Consolidated EBITDA to Consolidated Interest Charges 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. The ratio, per the agreement, is to be not less than 2.50 to 1.00. This covenant was met with a ratio of 8.09 to 1.00 as of December 31, 2018. DP&L does not have any meaningful restrictions in its debt financing documents prohibiting dividends to its parent, DPL. As of December 31, 2018 , DP&L was 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. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2018 | |
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 2018 2017 2016 Computation of tax expense / (benefit) Federal income tax expense / (benefit)(a) $ 6.7 $ (2.3 ) $ 4.3 Increases (decreases) in tax resulting from: State income taxes, net of federal effect 0.1 0.1 — Depreciation of flow-through differences (4.6 ) 1.1 3.3 Investment tax credit amortized (0.3 ) (0.3 ) (0.4 ) Deferred tax adjustments — (0.7 ) (9.3 ) Accrual (settlement) for open tax years — (0.4 ) 2.0 Other, net (b) (1.2 ) (2.5 ) (2.3 ) Tax expense / (benefit) $ 0.7 $ (5.0 ) $ (2.4 ) Components of tax expense / (benefit) Federal - current $ (17.9 ) $ 23.8 $ (3.3 ) State and Local - current 0.5 0.2 — Total current (17.4 ) 24.0 (3.3 ) Federal - deferred 18.3 (28.8 ) 0.8 State and local - deferred (0.2 ) (0.2 ) 0.1 Total deferred 18.1 (29.0 ) 0.9 Tax expense / (benefit) $ 0.7 $ (5.0 ) $ (2.4 ) (a) The statutory tax rate of 21% in 2018 and 35% in 2017 and 2016 was applied to pre-tax earnings. (b) Includes expense / (benefit) of $3.5 million and $(0.9) million in the years ended December 31, 2017 and 2016 , respectively, of income tax related to adjustments from prior years. The 2018 and 2017 tax years also include a remeasurement of deferred tax expense related to the recent enactment of the TCJA of a benefit of $(1.2) million and $(0.4) million , respectively. 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, 2018 , 2017 and 2016 : Years ended December 31, 2018 2017 2016 Statutory Federal tax rate 21.0 % 35.0 % 35.0 % State taxes, net of Federal tax benefit 0.4 % (1.5 )% 0.2 % AFUDC - equity (0.1 )% 4.9 % (5.0 )% Depreciation of flow-through differences (14.6 )% (17.6 )% 26.7 % Amortization of investment tax credits (1.0 )% 5.1 % (3.3 )% Deferred tax adjustments — % 11.0 % (75.1 )% Permanent differences — % 4.8 % 2.8 % Other, net (3.5 )% 35.2 % (0.7 )% Effective tax rate 2.2 % 76.9 % (19.4 )% 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 2018 2017 Net non-current assets / (liabilities) Depreciation / property basis $ (112.0 ) $ (113.4 ) Income taxes recoverable 25.0 11.0 Regulatory assets (15.4 ) (23.1 ) Investment tax credit 0.5 0.7 Compensation and employee benefits 1.4 19.0 Intangibles (0.3 ) (0.4 ) Long-term debt (2.1 ) (0.2 ) Other (a) (13.2 ) (7.1 ) Net non-current liabilities $ (116.1 ) $ (113.5 ) (a) The Other caption includes deferred tax assets of $10.9 million in 2018 and $9.3 million in 2017 related to state and local tax net operating loss carryforwards, net of related valuation allowances of $10.9 million in 2018 and $9.3 million in 2017 . These net operating loss carryforwards expire from 2019 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. In 2017, 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 2017 financial statements reflected the income tax effects of U.S. tax reform for which the accounting was complete and provisional amounts for those impacts for which the accounting under FASC 740 was incomplete, but a reasonable estimate could be determined. We completed our calculation of the impact of the TCJA in our income tax provision for the year ended December 31, 2018 in accordance with our understanding of the TCJA and guidance available as of the date of this filing, and as a result recognized $15.5 million and $13.7 million of discrete tax expense in the fourth quarter of 2018 and 2017 respectively. Of this total, tax benefits of $1.2 million and $0.4 million are included in continuing operations in 2018 and 2017, respectively. These amounts result from the remeasurement of certain deferred tax assets and liabilities as the rates changed from 35% to 21% . The most material deferred taxes to be remeasured related to property, plant and equipment. The remeasurements of deferred tax assets and liabilities related to regulated utility property of $17.0 million and $135.2 million at December 31, 2018 and 2017 were recorded as regulatory liabilities and were non-cash adjustments. 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 of the DMR, further accrued tax sharing liabilities will also be converted to additional equity. All parties agreed that the initial conversion and subsequent conversions will not be reversed. During the years ended December 31, 2018 and 2017 , we converted $40.0 million and $97.1 million , respectively, of accrued tax sharing liabilities with AES to additional equity investment in DPL 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 2018 2017 2016 Tax expense / (benefit) $ 0.2 $ 0.2 $ (9.6 ) 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, 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 Calendar 2018 Tax positions taken during prior period — Lapse of Statute of Limitations — Balance at December 31, 2018 $ 3.5 Of the December 31, 2018 balance of unrecognized tax benefits, $3.5 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 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. |
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 2018 2017 2016 Computation of tax expense Federal income tax expense (a) $ 22.2 $ 31.0 $ 50.1 Increases (decreases) in tax resulting from: State income taxes, net of federal effect 0.6 0.4 0.4 Depreciation of flow-through differences (4.3 ) 1.2 3.0 Investment tax credit amortized (0.3 ) (0.3 ) (0.4 ) Accrual (settlement) for open tax years — (0.5 ) 3.4 Other, net (b) (0.5 ) (0.7 ) (10.5 ) Total tax expense $ 17.7 $ 31.1 $ 46.0 Components of tax expense Federal - current $ 1.4 $ 13.5 $ 37.7 State and Local - current — 0.2 0.5 Total current 1.4 13.7 38.2 Federal - deferred 15.5 17.0 7.7 State and local - deferred 0.8 0.4 0.1 Total deferred 16.3 17.4 7.8 Total tax expense $ 17.7 $ 31.1 $ 46.0 (a) The statutory tax rate of 21% in 2018 and 35% in 2017 and 2016 was applied to pre-tax earnings. (b) Includes expense / (benefit) of $(0.7) million and $(0.4) million in the years ended December 31, 2017 and 2016 , 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, 2018 , 2017 and 2016 : Years ended December 31, 2018 2017 2016 Statutory Federal tax rate 21.0 % 35.0 % 35.0 % State taxes, net of Federal tax benefit 0.6 % 0.4 % 0.3 % AFUDC - Equity (0.1 )% 1.4 % 2.1 % Amortization of investment tax credits (0.3 )% (0.4 )% (0.3 )% Depreciation of flow-through differences (4.0 )% — % — % Other - net (0.2 )% (1.3 )% (5.1 )% Effective tax rate 17.0 % 35.1 % 32.0 % 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 2018 2017 Net non-current assets / (liabilities) Depreciation / property basis $ (130.6 ) $ (126.5 ) Income taxes recoverable 25.0 11.0 Regulatory assets (16.2 ) (23.9 ) Investment tax credit 0.5 0.4 Compensation and employee benefits 0.3 17.6 Other (10.7 ) (9.6 ) Net non-current liabilities $ (131.7 ) $ (131.0 ) U.S. Tax Reform On December 22, 2017, the U.S. enacted the TCJA. The TCJA significantly changes U.S. corporate income tax law. In 2017, 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 2017 financial statements reflected the income tax effects of U.S. tax reform for which the accounting was complete and provisional amounts for those impacts for which the accounting under FASC 740 was incomplete, but a reasonable estimate could be determined. We completed our calculation of the impact of the TCJA in our income tax provision for the year ended December 31, 2018 in accordance with our understanding of the TCJA and guidance available as of the date of this filing. As a result of this remeasurement, certain deferred tax assets and liabilities related to regulated utility property of $17.0 million and $135.2 million at December 31, 2018 and 2017 were recorded as regulatory liabilities and were non-cash adjustments. These amounts result from the remeasurement of certain deferred tax assets and liabilities as the rates changed from 35% to 21% . Additionally, consistent with the provisions of SAB 118, in 2018 we finalized the remeasurement of deferred tax asset balances transferred to AES Ohio Generation as part of Generation Separation which resulted in an additional $10.0 million return of capital to DPL in 2018. 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 2018 2017 2016 Tax expense / (benefit) $ (0.3 ) $ 4.0 $ (7.0 ) Uncertain Tax Positions We apply the provisions of GAAP relating to the accounting for uncertainty in income taxes. A reconciliation of the beginning and ending amount of unrecognized tax benefits for DP&L is as follows: $ in millions Balance at December 31, 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 Calendar 2018 Tax positions taken during prior period — Lapse of Statute of Limitations — Balance at December 31, 2018 $ 4.8 Of the December 31, 2018 balance of unrecognized tax benefits, $4.8 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, 2018 | |
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 $2,400 for 2018 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 $3.7 million, $3.1 million and $5.1 million for the years ended December 31, 2018, 2017 and 2016, 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. 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. 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 $9.2 million and $12.7 million at December 31, 2018 and 2017 , 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, 2018 and 2017 . 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 $1.8 million and $1.1 million of costs billed to the Service Company for the years ended December 31, 2018 and 2017 . $ in millions Years ended December 31, Change in benefit obligation 2018 2017 Benefit obligation at January 1 $ 436.9 $ 419.6 Service cost 6.1 5.7 Interest cost 13.8 14.2 Plan amendments 5.1 — Plan curtailment — 3.0 Actuarial (gain) / loss (34.6 ) 28.1 Benefits paid (40.8 ) (33.7 ) Benefit obligation at December 31 386.5 436.9 Change in plan assets Fair value of plan assets at January 1 357.5 341.0 Actual return on plan assets (11.7 ) 44.8 Employer contributions 7.9 5.4 Benefits paid (40.8 ) (33.7 ) Fair value of plan assets at December 31 312.9 357.5 Unfunded status of plan $ (73.6 ) $ (79.4 ) December 31, Amounts recognized in the Balance sheets 2018 2017 Current liabilities $ (0.4 ) $ (0.4 ) Non-current liabilities (73.2 ) (79.0 ) Net liability at end of year $ (73.6 ) $ (79.4 ) Amounts recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax Components: Prior service cost $ 9.1 $ 4.9 Net actuarial loss 103.3 111.4 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 112.4 $ 116.3 Recorded as: Regulatory asset $ 87.2 $ 92.1 Accumulated other comprehensive income 25.2 24.2 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 112.4 $ 116.3 The accumulated benefit obligation for our defined benefit pension plans was $378.7 million and $428.3 million at December 31, 2018 and 2017 , respectively. The net periodic benefit cost of the pension plans was: Years ended December 31, $ in millions 2018 2017 2016 Service cost $ 6.1 $ 5.7 $ 5.7 Interest cost 13.8 14.2 14.7 Expected return on assets (21.2 ) (22.8 ) (22.8 ) Plan curtailment (a) — 4.1 3.8 Amortization of unrecognized: Actuarial loss 6.4 5.3 4.3 Prior service cost 0.9 1.1 1.8 Net periodic benefit cost $ 6.0 $ 7.6 $ 7.5 Rates relevant to each year's expense calculations Discount rate 3.66 % 4.28 % 4.49 % Expected return on plan assets 6.25 % 6.50 % 6.50 % (a) As a result of the decision to retire certain coal-fired plants, we recognized a plan curtailment of $4.1 million and $3.8 million in 2017 and 2016, respectively. 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 2018 2017 2016 Net actuarial loss $ 3.4 $ 9.1 $ 20.9 Plan curtailment (a) — (4.1 ) (3.8 ) Reversal of amortization item: Net actuarial loss (6.4 ) (5.3 ) (4.3 ) Prior service cost (0.9 ) (1.1 ) (1.8 ) Total recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities $ (3.9 ) $ (1.4 ) $ 11.0 Total recognized in net periodic benefit cost and Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities $ 2.1 $ 6.2 $ 18.5 (a) As a result of the decision to retire certain coal-fired plants, we recognized a plan curtailment of $4.1 million and $3.8 million in 2017 and 2016, respectively. Significant Gains and Losses Related to Changes in the Benefit Obligation The actuarial gain of $34.6 million decreased the benefit obligation for the year ended December 31, 2018 and an actuarial loss of $28.1 million increased the benefit obligation for the year ended December 31, 2017 . The actuarial gain in 2018 was primarily due to an increase in the discount rate, while the actuarial loss in 2017 was primarily due to a decrease in the discount rate. 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, 2018 , we are maintaining our long-term rate of return assumption of 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, 2018 , we have increased our assumed discount rate to 4.35% from 3.66% 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 2019 pension expense of approximately $3.2 million . A one percent decrease in the rate of return assumption for pension would result in an increase in 2019 pension expense of approximately $3.2 million . A 25 -basis point increase in the discount rate for pension would result in a decrease of approximately $0.1 million to 2019 pension expense. A 25 -basis point decrease in the discount rate for pension would result in an increase of approximately $0.4 million to 2019 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, 2018 . 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. 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. 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, 2018 , 2017 and 2016 were: Benefit Obligation Assumptions Pension 2018 2017 2016 Discount rate for obligations 4.35% 3.66% 4.28% 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 2018 : Long-Term Percentage of plan assets as of December 31, Asset category 2018 2017 Equity Securities 38% 33% 35% Debt Securities 56% 58% 55% Cash and Cash Equivalents —% 1% —% Real Estate 6% 8% 10% The fair values of our pension plan assets at December 31, 2018 by asset category are as follows: Fair Value Measurements for Pension Plan Assets at December 31, 2018 $ in millions Market Value at December 31, 2018 Quoted prices Significant Significant Asset category (Level 1) (Level 2) (Level 3) Mutual funds: U.S. equities (a) $ 79.3 $ 79.3 $ — $ — International equities (a) 25.9 25.9 — — Fixed income (b) 143.7 143.7 — — Fixed income securities: U.S. Treasury securities 37.5 37.5 — — Cash and cash equivalents: Money market funds (c) 2.4 2.4 — — Other investments: Core property collective fund (d) 24.1 — 24.1 — Total pension plan assets $ 312.9 $ 288.8 $ 24.1 $ — (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 is comprised of investments in U.S. treasury obligations that seek to preserve principal and maintain liquidity while providing current income. The funds are valued at the assets’ amortized cost to maintain a stable per share net asset value. (d) 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, 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: (c) Core property collective fund 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. 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 $7.5 million to the pension plan in the year ended December 31, 2018 and $5.0 million to the pension plan in each of the years ended December 31, 2017 and 2016. We expect to make contributions of $0.4 million to our SERP in 2019 to cover benefit payments. We also expect to make contributions of $7.5 million to our pension plan during 2019 . 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 101% . In addition, DP&L must also contribute the normal service cost earned by active participants during the plan year. The funding of normal cost is expected to be approximately $5.4 million in 2019 , which includes $1.9 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 2019 $ 26.7 2020 $ 26.5 2021 $ 26.3 2022 $ 26.0 2023 $ 25.9 2024 - 2028 $ 125.1 |
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 $2,400 for 2018 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 $3.7 million, $3.1 million and $5.1 million for the years ended December 31, 2018, 2017 and 2016, 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. 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. 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 $9.2 million and $12.7 million at December 31, 2018 and 2017 , 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, 2018 and 2017 . 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 $1.8 million and $1.1 million of costs billed to the Service Company for the years ended December 31, 2018 and 2017 or $3.3 million and $0.7 million of costs billed to AES Ohio Generation for the years ended December 31, 2018 and 2017 . $ in millions Years ended December 31, Change in benefit obligation 2018 2017 Benefit obligation at January 1 $ 436.9 $ 419.6 Service cost 6.1 5.7 Interest cost 13.8 14.2 Plan amendments 5.1 — Plan curtailment — 3.0 Actuarial (gain) / loss (34.6 ) 28.1 Benefits paid (40.8 ) (33.7 ) Benefit obligation at December 31 386.5 436.9 Change in plan assets Fair value of plan assets at January 1 357.5 341.0 Actual return on plan assets (11.7 ) 44.8 Employer contributions 7.9 5.4 Benefits paid (40.8 ) (33.7 ) Fair value of plan assets at December 31 312.9 357.5 Unfunded status of plan $ (73.6 ) $ (79.4 ) December 31, Amounts recognized in the Balance sheets 2018 2017 Current liabilities $ (0.4 ) $ (0.4 ) Non-current liabilities (73.2 ) (79.0 ) Net liability at end of year $ (73.6 ) $ (79.4 ) Amounts recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax Components: Prior service cost $ 10.4 $ 6.7 Net actuarial loss 137.2 148.3 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 147.6 $ 155.0 Recorded as: Regulatory asset $ 87.3 $ 92.2 Accumulated other comprehensive income 60.3 62.8 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 147.6 $ 155.0 The accumulated benefit obligation for our defined benefit pension plans was $378.7 million and $428.3 million at December 31, 2018 and 2017 , respectively. The net periodic benefit cost of the pension plans was: Years ended December 31, $ in millions 2018 2017 2016 Service cost $ 6.1 $ 5.7 $ 5.7 Interest cost 13.8 14.2 14.7 Expected return on assets (21.2 ) (22.8 ) (22.8 ) Plan curtailment (a) — 5.6 5.7 Amortization of unrecognized: Actuarial loss 9.4 8.7 7.2 Prior service cost 1.4 1.5 3.0 Net periodic benefit cost $ 9.5 $ 12.9 $ 13.5 Rates relevant to each year's expense calculations Discount rate 3.66 % 4.28 % 4.49 % Expected return on plan assets 6.25 % 6.50 % 6.50 % (a) As a result of the decision to retire certain coal-fired plants, we recognized a plan curtailment of $5.6 million and $5.7 million in 2017 and 2016, respectively. 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 2018 2017 2016 Net actuarial loss $ 3.4 $ 9.1 $ 20.9 Plan curtailment (a) — (5.6 ) (5.7 ) Reversal of amortization item: Net actuarial loss (9.4 ) (8.7 ) (7.2 ) Prior service cost (1.4 ) (1.5 ) (3.0 ) Total recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities $ (7.4 ) $ (6.7 ) $ 5.0 Total recognized in net periodic benefit cost and Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities $ 2.1 $ 6.2 $ 18.5 (a) As a result of the decision to retire certain coal-fired plants, we recognized a plan curtailment of $5.6 million and $5.7 million in 2017 and 2016, respectively. Significant Gains and Losses Related to Changes in the Benefit Obligation The actuarial gain of $34.6 million decreased the benefit obligation for the year ended December 31, 2018 and an actuarial loss of $28.1 million increased the benefit obligation for the year ended December 31, 2017 . The actuarial gain in 2018 was primarily due to an increase in the discount rate, while the actuarial loss in 2017 was primarily due to a decrease in the discount rate. 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, 2018 , we are maintaining our long-term rate of return assumption of 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, 2018 , we have increased our assumed discount rate to 4.35% from 3.66% 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 2019 pension expense of approximately $3.2 million . A one percent decrease in the rate of return assumption for pension would result in an increase in 2019 pension expense of approximately $3.2 million . A 25 -basis point increase in the discount rate for pension would result in a decrease of approximately $0.1 million to 2019 pension expense. A 25 -basis point decrease in the discount rate for pension would result in an increase of approximately $0.4 million to 2019 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, 2018 . 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. 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, 2018 , 2017 and 2016 were: Benefit Obligation Assumptions Pension 2018 2017 2016 Discount rate for obligations 4.35% 3.66% 4.28% 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 2018 : Long-Term Percentage of plan assets as of December 31, Asset category 2018 2017 Equity Securities 38% 33% 35% Debt Securities 56% 58% 55% Cash and Cash Equivalents —% 1% —% Real Estate 6% 8% 10% The fair values of our pension plan assets at December 31, 2018 by asset category are as follows: Fair Value Measurements for Pension Plan Assets at December 31, 2018 $ in millions Market Value at December 31, 2018 Quoted prices Significant Significant Asset category (Level 1) (Level 2) (Level 3) Mutual funds: U.S. equities (a) $ 79.3 $ 79.3 $ — $ — International equities (a) 25.9 25.9 — — Fixed income (b) 143.7 143.7 — — Fixed income securities: U.S. Treasury securities 37.5 37.5 — — Cash and cash equivalents: Money market funds (c) 2.4 2.4 — — Other investments: Core property collective fund (d) 24.1 — 24.1 — Total pension plan assets $ 312.9 $ 288.8 $ 24.1 $ — (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 is comprised of investments in U.S. treasury obligations that seek to preserve principal and maintain liquidity while providing current income. The funds are valued at the assets’ amortized cost to maintain a stable per share net asset value. (d) 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, 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: (c) Core property collective fund 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. 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 $7.5 million to the pension plan in the year ended December 31, 2018 and $5.0 million to the pension plan in each of the years ended December 31, 2017 and 2016. We expect to make contributions of $0.4 million to our SERP in 2019 to cover benefit payments. We also expect to make contributions of $7.5 million to our pension plan during 2019 . 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 101% . In addition, DP&L must also contribute the normal service cost earned by active participants during the plan year. The funding of normal cost is expected to be approximately $5.4 million in 2019 , which includes $1.9 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 2019 $ 26.7 2020 $ 26.5 2021 $ 26.3 2022 $ 26.0 2023 $ 25.9 2024 - 2028 $ 125.1 |
Equity
Equity | 12 Months Ended |
Dec. 31, 2018 | |
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, 2018 . 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 on 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, 2018 , DPL’s leverage ratio was at 1.47 to 1.00 and DPL’s senior long-term debt rating from a major credit rating agency was below investment grade. As a result, as of December 31, 2018 , 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 50,000,000 authorized common shares, of which 41,172,173 are outstanding at December 31, 2018 . All common shares are held by DP&L’s parent, DPL . 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. For the year ended December 31, 2018, AES made capital contributions of $40.0 million by converting the amount owed to it by DPL related to tax-sharing payments for current tax liabilities. See Note 8 – 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 50,000,000 authorized common shares, of which 41,172,173 are outstanding at December 31, 2018 . All common shares are held by DP&L’s parent, DPL . 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 2018, DP&L received an $80.0 million capital contribution from its parent, DPL. In addition, DP&L made returns of capital payments of $43.8 million to DPL. In addition, DP&L recorded $10.0 million in 2018 as a return of capital to transfer additional deferred tax amounts under Generation Separation. See Note 8 – Income Taxes and Note 14 – Generation Separation for more information. 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 14 – 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, 2018 | |
Contractual Obligations, Commercial Commitments and Contingencies | Contractual Obligations, Commercial Commitments and Contingencies 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, 2018 , DPL had $23.6 million of guarantees on behalf of AES Ohio Generation to third parties for future financial or performance assurance under such agreements. The guarantee arrangements entered into by DPL with these third parties cover present and future obligations of AES Ohio Generation to such beneficiaries and are terminable at any time by DPL upon written notice to the beneficiaries. We had no outstanding balance of obligations for commercial transactions covered by these guarantees at December 31, 2018. The carrying amount of obligations for commercial transactions covered by these guarantees and recorded in our Consolidated Balance Sheets was $0.9 million at December 31, 2017. 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, 2018 , DP&L could be responsible for the repayment of 4.9% , or $68.1 million , of a $1,389.6 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. One of the other OVEC members, with a 4.85% interest in OVEC, filed for bankruptcy protection and the bankruptcy court approved that member's rejection of the OVEC arrangement and its related obligations on July 31, 2018. We do not expect these events to have a material impact on our financial condition, results of operations or cash flows. 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, 2018 , these include: Payments due in: $ in millions Total Less than 2 - 3 4 - 5 More than Electricity purchase commitments $ 209.4 $ 139.5 $ 69.9 $ — $ — Purchase orders and other contractual obligations $ 40.2 $ 11.4 $ 14.8 $ 14.0 $ — 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. Purchase orders and other contractual obligations: At December 31, 2018 , 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, 2018 , cannot be reasonably determined. Environmental Matters DPL’s facilities and operations are subject to a wide range of federal, state and local environmental laws, rules and regulations. The environmental issues that may affect us include the following. However, as described further below, as a result of DPL’s retirement of its Stuart and Killen generating stations, the sale of its ownership interest in the Miami Fort and Zimmer generating stations, the planned 2020 retirement of Conesville and our exiting of our generation business, certain of these environmental regulations and laws are now not expected to have a material impact on DPL with respect to these generating stations. • 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. • 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, rules 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 laws, rules and 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 current and previously owned and operated coal-fired generation units. Some of these matters could have material adverse impacts on our results of operations, financial condition or cash flows. |
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, 2018 , DP&L could be responsible for the repayment of 4.9% , or $68.1 million , of a $1,389.6 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. One of the other OVEC members, with a 4.85% interest in OVEC, filed for bankruptcy protection and the bankruptcy court approved that member's rejection of the OVEC arrangement and its related obligations on July 31, 2018. We do not expect these events to have a material impact on our financial condition, results of operations or cash flows. 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, 2018 , these include: Payments due in: $ in millions Total Less than 2 - 3 4 - 5 More than Electricity purchase commitments $ 209.4 $ 139.5 $ 69.9 $ — $ — Purchase orders and other contractual obligations $ 39.8 $ 11.3 $ 14.7 $ 13.8 $ — 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, 2018 , 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, 2018 , cannot be reasonably determined. Environmental Matters DP&L's facilities and operations are subject to a wide range of federal, state and local environmental laws, rules and regulations. The environmental issues that may affect us include the following. However, as described further below, as a result of DPL’s retirement of its Stuart and Killen generating stations, the sale of its ownership interest in the Miami Fort and Zimmer generating stations, the planned 2020 retirement of Conesville and our exiting of our generation business, certain of these environmental regulations and laws are now not expected to have a material impact on DPL with respect to these generating stations. • 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, rules 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 laws, rules and 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 current and previously owned and operated coal-fired generation units. Some of these matters could have material adverse impacts on our results of operations, financial condition or cash flows. |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2018 | |
Entity Information [Line Items] | |
Related Party Transactions | Related Party Transactions Service Company The Service Company allocates the costs for services provided 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 2018 , 2017 and 2016 , 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. Restricted stock units vest ratably over a three-year period. The performance units payable in cash vest at the end of the three-year performance period and are subject to certain AES performance criteria. Total deferred compensation expense recorded during 2018 , 2017 and 2016 was $0.4 million , $0.4 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 our related party transactions: Years ended December 31, $ in millions 2018 2017 2016 Transactions with the Service Company Charges for services provided $ 41.0 $ 46.5 $ 42.8 Charges to the Service Company $ 4.9 $ 4.2 $ 4.6 Transactions with other AES affiliates: Payments for health, welfare and benefit plans $ 7.9 $ 15.4 $ 9.6 Consulting services $ 2.0 $ — $ — Balances with related parties: At December 31, 2018 At December 31, 2017 Net payable to the Service Company $ (4.8 ) $ (3.9 ) Net payable to other AES affiliates $ (0.5 ) $ (0.6 ) 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 $0.2 million and $0.3 million at December 31, 2018 and 2017 , 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, 2018 and 2017 , respectively, that was established upon the Trust’s deconsolidation in 2003. See Note 7 – Long-term 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. 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 8 – Income Taxes for more information. |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Entity Information [Line Items] | |
Related Party Transactions | Related Party Transactions Service Company The Service Company allocates the costs for services provided 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 2018 , 2017 and 2016 , 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. Restricted stock units vest ratably over a three-year period. The performance units payable in cash vest at the end of the three-year performance period and are subject to certain AES performance criteria. Total deferred compensation expense recorded during 2018 , 2017 and 2016 was $0.3 million , $0.4 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 our related party transactions: Years ended December 31, $ in millions 2018 2017 2016 DP&L Cost of revenues: Fuel and power purchased from AES Ohio Generation $ — $ 5.4 $ 8.7 DP&L Operation & Maintenance Expenses: Premiums charged for insurance services provided by MVIC (a) $ 2.7 $ 3.1 $ 3.4 Transactions with the Service Company: Charges for services provided $ 25.7 $ 39.0 $ 38.7 Charges to the Service Company $ 4.9 $ 4.2 $ 4.5 Transactions with other AES affiliates: Charges for health, welfare and benefit plans $ 8.7 $ 14.3 $ 9.4 Charges to affiliates for non-power goods or services (b) $ 7.1 $ 3.7 $ 5.7 Consulting services $ 2.0 $ — $ — Balances with related parties: At December 31, 2018 At December 31, 2017 Net payable to the Service Company $ (4.8 ) $ (3.9 ) Net receivable from / (payable) to other AES affiliates $ (0.5 ) $ 4.8 (a) 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 . (b) In the normal course of business DP&L incurred and recorded expenses on behalf of DPL affiliates. 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 $19.6 million and $6.5 million at December 31, 2018 and 2017, respectively, which is recorded in Taxes receivable on the accompanying Balance Sheets. During 2018 , 2017 and 2016 , DP&L made net payments of $14.6 million , $28.1 million and $0.0 million respectively, to DPL for its share of income taxes. |
Business Segments
Business Segments | 12 Months Ended |
Dec. 31, 2018 | |
Segment Reporting Information [Line Items] | |
Business Segments | Business Segments Beginning with the second quarter of 2018, DPL has presented the results of operations of Miami Fort Station, Zimmer Station, the Peaker Assets, Stuart Station and Killen Station as discontinued operations as a group of components for all periods presented. For more information, see Note 15 – Discontinued Operations of Notes to DPL's Consolidated Financial Statements . AES Ohio Generation now only has operating activity coming from its undivided ownership interest in Conesville, which does not meet the threshold to be a separate reportable operating segment. Because of this, DPL now manages its business through only one reportable operating segment, the Utility 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 Utility segment is discussed further below: Utility Segment The Utility 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 525,000 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 Utility segment includes revenues and costs associated with our investment in OVEC and the historical results of DP&L’s Beckjord Facility, which was closed in 2014 and transferred to a third party in the first quarter of 2018, and the Hutchings EGU, which was closed in 2013. These assets did not transfer to AES Ohio Generation as part of DP&L's Generation Separation on October 1, 2017. Thus, they are grouped within the Utility segment for segment reporting purposes. In addition, regulatory deferrals and collections, which include fuel deferrals in historical periods, are included in the Utility segment. 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 long-term debt and adjustments related to purchase accounting from the Merger. DPL's undivided interest in Conesville is now included within the "Other" column as it no longer meets the requirement for disclosure as a reportable operating segment, since the results of operations of the other generation plants are now presented as discontinued operations. 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 DPL’s reportable business segment: $ in millions Utility Other (a) Adjustments and Eliminations DPL Consolidated Year ended December 31, 2018 Revenues from external customers $ 737.8 $ 38.1 $ — $ 775.9 Intersegment revenues 0.9 2.9 (3.8 ) — Total revenues $ 738.7 $ 41.0 $ (3.8 ) $ 775.9 Depreciation and amortization $ 74.5 $ (1.4 ) $ — $ 73.1 Fixed-asset impairment $ — $ 2.8 $ — $ 2.8 Interest expense $ 27.3 $ 70.7 $ — $ 98.0 Income / (loss) from continuing operations before income tax $ 104.4 $ (72.5 ) $ — $ 31.9 Cash capital expenditures $ 93.1 $ 10.5 $ — $ 103.6 Total assets (end of year) $ 1,819.6 $ 545.9 $ (482.4 ) $ 1,883.1 $ in millions Utility Other (a) Adjustments and Eliminations DPL Consolidated Year ended December 31, 2017 Revenues from external customers $ 718.9 $ 25.0 $ — $ 743.9 Intersegment revenues 1.1 4.4 (5.5 ) — Total revenues $ 720.0 $ 29.4 $ (5.5 ) $ 743.9 Depreciation and amortization $ 75.3 $ 0.8 $ — $ 76.1 Interest expense $ 30.5 $ 79.5 $ — $ 110.0 Income / (loss) from continuing operations before income tax $ 88.5 $ (95.0 ) $ — $ (6.5 ) Cash capital expenditures $ 85.6 $ 35.9 $ — $ 121.5 Total assets (end of year) $ 1,695.9 $ 736.5 $ (383.2 ) $ 2,049.2 $ in millions Utility Other (a) Adjustments and Eliminations DPL Consolidated Year ended December 31, 2016 Revenues from external customers $ 806.7 $ 27.5 $ — $ 834.2 Intersegment revenues 1.3 5.7 (7.0 ) — Total revenues $ 808.0 $ 33.2 $ (7.0 ) $ 834.2 Depreciation and amortization $ 71.0 $ 2.6 $ — $ 73.6 Fixed-asset impairment $ — $ 23.9 $ — $ 23.9 Interest expense $ 25.4 $ 82.3 $ (0.3 ) $ 107.4 Income / (loss) from continuing operations before income tax $ 143.0 $ (130.6 ) $ — $ 12.4 Cash capital expenditures $ 83.4 $ 65.1 $ — $ 148.5 Total assets (end of year) $ 1,710.5 $ 1,145.9 $ (437.2 ) $ 2,419.2 (a) "Other" includes Cash capital expenditures and Total assets related to the assets of discontinued operations and held-for-sale businesses for all periods presented. |
Revenue (Notes)
Revenue (Notes) | 12 Months Ended |
Dec. 31, 2018 | |
Revenue from Contract with Customer [Text Block] | Revenue Revenue is primarily earned from retail and wholesale electricity sales and electricity transmission and distribution delivery services. Revenue is recognized upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Revenue is recorded net of any taxes assessed on and collected from customers, which are remitted to the governmental authorities. Retail Revenues – DP&L energy sales to utility customers are based on the reading of meters at the customer's location that occurs on a systematic basis throughout the month. DP&L sells electricity directly to end-users, such as homes and businesses, and bills customers directly. Performance obligations for retail revenues are satisfied over time as energy is delivered and the same method is used to measure progress, and thus the performance obligation meets the criteria to be considered a series. This includes both the promise to transfer energy and other distribution and/or transmission services. In exchange for the exclusive right to sell or distribute electricity in our service area, DP&L is subject to rate regulation by federal and state regulators. This regulation sets the framework for the prices (“tariffs”) that DP&L is allowed to charge customers for electricity. Since tariffs are approved by the regulator, the price that DP&L has the right to bill corresponds directly with the value to the customer of DP&L's performance completed in each period. Therefore, revenue under these contracts is recognized using an output method measured by the MWhs delivered each month at the approved tariff. In cases where a customer chooses to receive generation services from a CRES provider, the price for generation services is negotiated between the customer and the CRES provider, and DP&L only serves as a billing agent if requested by the CRES provider. As such, DP&L recognizes the consolidated billing arrangement with the CRES provider on a net basis, thereby recording no revenue for the generation component. Retail revenue from these customers would only be related to transmission and distribution charges. Wholesale Revenues – All of the power produced from DPL's ownership interest in Conesville and DP&L's share of the power produced at OVEC is sold to PJM and these are classified as Wholesale revenues. In PJM, the promise to sell energy as wholesale revenue is separately identifiable from participation in the capacity market and the two products can be transacted independently of one another. Therefore, wholesale revenues are a separate contract with a single performance obligation. Revenue is recorded based on the quantities (MWh) delivered in each hour during each month at the spot price, making the contract effectively “month-to-month”. RTO Revenues – Compensation for use of DP&L’s transmission assets and compensation for various ancillary services are classified as RTO revenues. As DP&L owns and operates transmission lines in southwest Ohio within PJM, demand charges collected from network customers by PJM are then allocated to the appropriate transmission owners (i.e. DP&L ) and recognized as transmission revenues. Additionally, as an owner of generation and transmission assets within PJM, DPL is compensated for various ancillary services; such as reactive supply, regulation services, scheduling reserves, operating reserves, spinning/synchronized reserves as well as congestion credits that are provided to PJM via these assets. Transmission revenues have a single performance obligation, as transmission services represent a distinct service. Additionally, as the performance obligation is satisfied over time and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series. The price that DP&L , as the transmission operator, has the right to bill (received as a credit from PJM) corresponds directly with the value to the customer of performance completed in each period, as the price paid is the allocation of the tariff rate (as approved by the regulator) charged to network participants. Ancillary service revenues have a single performance obligation, as they represent a distinct service. Additionally, as the performance obligation is satisfied over time and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series. The price that DPL has the right to bill corresponds directly with the value to the customer of performance completed in each period as the price paid is at the market price or allocation of the tariff rate (which was approved by the regulator) charged to network participants. RTO Capacity Revenues – Compensation received from PJM for making installed generation capacity available to satisfy system integrity and reliability requirements is classified as RTO capacity revenues. Capacity, which is a stand-ready obligation to deliver energy when called upon by the RTO, is measured using MWs. If plant availability exceeds a contractual target, we may receive a performance bonus payment, or if the plant availability falls below a guaranteed minimum target, we may incur a non-availability penalty. Such bonuses or penalties represent a form of variable consideration and are estimated and recognized when it is probable that there will not be a significant reversal and therefore the transaction price is recognized on an output basis based on the MWs. RTO capacity revenues have a single performance obligation, as capacity is a distinct good. Additionally, as the performance obligation is satisfied over time and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series. The capacity price is set through a competitive auction process established by PJM. DPL's revenue from contracts with customers was $743.8 million for the year ended December 31, 2018 . The following table presents our revenue from contracts with customers and other revenue by segment for the year ended December 31, 2018 : $ in millions Utility Other Adjustments and Eliminations Total Year ended December 31, 2018 Retail Revenue Retail revenue from contracts with customers $ 625.8 $ — $ (1.0 ) $ 624.8 Other retail revenues (a) 32.1 — — 32.1 Wholesale Revenue Wholesale revenue from contracts with customers 29.9 22.1 — 52.0 RTO revenue 43.1 0.1 — 43.2 RTO capacity revenues 7.8 6.6 — 14.4 Other revenues from contracts with customers (b) — 9.4 — 9.4 Other revenues — 2.8 (2.8 ) — Total revenues $ 738.7 $ 41.0 $ (3.8 ) $ 775.9 (a) Other retail revenue primarily includes alternative revenue programs not accounted for under FASC 606. (b) Other revenues from contracts with customers primarily includes revenues for various services provided by Miami Valley Lighting. The balances of receivables from contracts with customers were $72.6 million and $63.0 million as of December 31, 2018 and January 1, 2018, respectively . Payment terms for all receivables from contracts with customers are typically within 30 days. We have elected to apply the optional disclosure exemptions under FASC 606. Therefore, we have no disclosures pertaining to revenue expected to be recognized in any future year related to remaining performance obligations, as we exclude contracts with an original length of one year or less, contracts for which we recognize revenue based on the amount we have the right to invoice for services performed, and variable consideration allocated entirely to a wholly unsatisfied performance obligation when the consideration relates specifically to our efforts to satisfy the performance obligation and depicts the amount to which we expect to be entitled for DPL. |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Revenue from Contract with Customer [Text Block] | Revenue Revenue is primarily earned from retail and wholesale electricity sales and electricity transmission and distribution delivery services. Revenue is recognized upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Revenue is recorded net of any taxes assessed on and collected from customers, which are remitted to the governmental authorities. Retail Revenues – DP&L energy sales to utility customers are based on the reading of meters at the customer's location that occurs on a systematic basis throughout the month. DP&L sells electricity directly to end-users, such as homes and businesses, and bills customers directly. Performance obligations for retail revenues are satisfied over time as energy is delivered and the same method is used to measure progress, and thus the performance obligation meets the criteria to be considered a series. This includes both the promise to transfer energy and other distribution and/or transmission services. In exchange for the exclusive right to sell or distribute electricity in our service area, DP&L is subject to rate regulation by federal and state regulators. This regulation sets the framework for the prices (“tariffs”) that DP&L is allowed to charge customers for electricity. Since tariffs are approved by the regulator, the price that DP&L has the right to bill corresponds directly with the value to the customer of DP&L's performance completed in each period. Therefore, revenue under these contracts is recognized using an output method measured by the MWhs delivered each month at the approved tariff. In cases where a customer chooses to receive generation services from a CRES provider, the price for generation services is negotiated between the customer and the CRES provider, and DP&L only serves as a billing agent if requested by the CRES provider. As such, DP&L recognizes the consolidated billing arrangement with the CRES provider on a net basis, thereby recording no revenue for the generation component. Retail revenue from these customers would only be related to transmission and distribution charges. Wholesale Revenues – DP&L's share of the power produced at OVEC is sold to PJM and is classified as Wholesale revenues. In PJM, the promise to sell energy as wholesale revenue is separately identifiable from participation in the capacity market and the two products can be transacted independently of one another. Therefore, wholesale revenues are a separate contract with a single performance obligation. Revenue is recorded based on the quantities (MWh) delivered in each hour during each month at the spot price, making the contract effectively “month-to-month”. RTO Revenues – Compensation for use of DP&L’s transmission assets and compensation for various ancillary services are classified as RTO revenues. As DP&L owns and operates transmission lines in southwest Ohio within PJM, demand charges collected from network customers by PJM are then allocated to the appropriate transmission owners (i.e. DP&L ) and recognized as transmission revenues. Additionally, as an owner of generation and transmission assets within PJM, DPL is compensated for various ancillary services; such as reactive supply, regulation services, scheduling reserves, operating reserves, spinning/synchronized reserves as well as congestion credits that are provided to PJM via these assets. Transmission revenues have a single performance obligation, as transmission services represent a distinct service. Additionally, as the performance obligation is satisfied over time and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series. The price that DP&L , as the transmission operator, has the right to bill (received as a credit from PJM) corresponds directly with the value to the customer of performance completed in each period, as the price paid is the allocation of the tariff rate (as approved by the regulator) charged to network participants. RTO Capacity Revenues – Compensation received from PJM for making installed generation capacity available to satisfy system integrity and reliability requirements is classified as RTO capacity revenues. Capacity, which is a stand-ready obligation to deliver energy when called upon by the RTO, is measured using MWs. If plant availability exceeds a contractual target, we may receive a performance bonus payment, or if the plant availability falls below a guaranteed minimum target, we may incur a non-availability penalty. Such bonuses or penalties represent a form of variable consideration and are estimated and recognized when it is probable that there will not be a significant reversal and therefore the transaction price is recognized on an output basis based on the MWs. RTO capacity revenues have a single performance obligation, as capacity is a distinct good. Additionally, as the performance obligation is satisfied over time and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series. The capacity price is set through a competitive auction process established by PJM. DP&L's revenue from contracts with customers was $706.6 million for the year ended December 31, 2018 . The following table presents our revenue from contracts with customers and other revenue by segment for the year ended December 31, 2018 : Year ended December 31, $ in millions 2018 Retail Revenue Retail revenue from contracts with customers $ 625.8 Other retail revenues (a) 32.1 Wholesale Revenue Wholesale revenue from contracts with customers 29.9 RTO revenue 43.1 RTO capacity revenues 7.8 Total revenues $ 738.7 (a) Other retail revenue primarily includes alternative revenue programs not accounted for under FASC 606. The balances of receivables from contracts with customers were $70.1 million and $62.1 million as of December 31, 2018 and January 1, 2018, respectively . Payment terms for all receivables from contracts with customers are typically within 30 days. We have elected to apply the optional disclosure exemptions under FASC 606. Therefore, we have no disclosures pertaining to revenue expected to be recognized in any future year related to remaining performance obligations, as we exclude contracts with an original length of one year or less, contracts for which we recognize revenue based on the amount we have the right to invoice for services performed, and variable consideration allocated entirely to a wholly unsatisfied performance obligation when the consideration relates specifically to our efforts to satisfy the performance obligation and depicts the amount to which we expect to be entitled for DP&L. |
Discontinued Operations
Discontinued Operations | 12 Months Ended |
Dec. 31, 2018 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Discontinued Operations | Discontinued Operations 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, which resulted in a gain on sale of $14.0 million for the year ended December 31, 2017. On March 27, 2018, DPL and AES Ohio Generation completed the sale transaction of the Peaker assets to Kimura Power, LLC, which resulted in a loss on sale of $1.9 million for the year ended December 31, 2018. Further, on May 31, 2018, DPL and AES Ohio Generation retired the Stuart Station coal-fired and diesel-fired generating units and the Killen Station coal-fired generating unit and combustion turbine, as planned. Consequently, in the second quarter of 2018, DPL determined that the disposal of this group of components as a whole represents a strategic shift by us to exit generation, and, as such, qualifies to be presented as discontinued operations. Therefore, the results of operations and financial position for this group of components were reported as such in the Consolidated Statements of Operations and Consolidated Balance Sheets for all periods presented. Previously, on January 1, 2016, DPL closed on the sale of DPLER, its competitive retail business. The sale agreement was signed on December 28, 2015, and DPL received $75.5 million of restricted cash on December 31, 2015 for the sale. 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. As such, the results of operations of DPLER were also reported as discontinued operations in the Consolidated Statements of Operations for the year ended December 31, 2016. The following table summarizes the major categories of assets and liabilities at the dates indicated: $ in millions December 31, 2018 December 31, 2017 Restricted cash $ — $ 1.5 Accounts receivable, net 4.0 37.9 Inventories — 19.4 Taxes applicable to subsequent years 2.3 7.4 Other prepayments and current assets 2.4 17.4 Property, plant & equipment, net — 232.2 Intangible assets, net 5.3 5.5 Other deferred assets — 0.6 Total assets of the disposal group classified as assets of discontinued operations and held-for-sale businesses in the balance sheets $ 14.0 $ 321.9 Accounts payable $ 3.9 $ 25.1 Accrued taxes 3.1 6.3 Other current liabilities 5.2 30.0 Long-term debt (a) — 0.3 Deferred taxes (b) (39.8 ) (2.3 ) Taxes payable 2.3 7.4 Pension, retiree and other benefits 9.7 10.6 Asset retirement obligations 90.4 116.6 Other deferred credits 6.6 5.9 Total liabilities of the disposal group classified as liabilities of discontinued operations and held-for-sale businesses in the balance sheets $ 81.4 $ 199.9 (a) Long-term debt relates to capital leases. (b) Deferred taxes represent the tax asset position of the discontinued group of components, which were netted with liabilities on DPL prior to classification as discontinued operations. The following table summarizes the revenues, cost of revenues, operating and other expenses and income tax of discontinued operations for the periods indicated: Years ended December 31, $ in millions 2018 2017 2016 Revenues $ 158.6 $ 492.9 $ 593.0 Cost of revenues (74.3 ) (249.5 ) (349.6 ) Operating and other expenses (13.8 ) (195.0 ) (214.6 ) Fixed-asset impairment — (175.8 ) (835.2 ) Income / (loss) from discontinued operations 70.5 (127.4 ) (806.4 ) Gain / (loss) from disposal of discontinued operations (1.6 ) 14.0 49.2 Income tax expense / (benefit) from discontinued operations 30.0 (20.3 ) (257.2 ) Net income / (loss) from discontinued operations $ 38.9 $ (93.1 ) $ (500.0 ) Cash flows related to discontinued operations are included in our Consolidated Statements of Cash Flows. Cash flows from operating activities for discontinued operations were $(6.8) million , $126.8 million and $92.3 million for the years ended December 31, 2018, 2017 and 2016, respectively. Cash flows from investing activities for discontinued operations were $233.8 million , $51.8 million and $(56.8) million for the years ended December 31, 2018, 2017 and 2016, respectively. The PUCO authorized DP&L to maintain long-term debt of $750.0 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 interest expense is included in the discontinued operations above. The interest expense included in discontinued operations was $0.2 million and $0.5 million for the years December 31, 2017 and 2016, respectively. AROs of Discontinued Operations DPL's retired Stuart and Killen generating facilities continue to carry ARO liabilities consisting primarily of river intake and discharge structures, coal unloading facilities, landfills, and ash disposal facilities. In the fourth quarter of 2018, DPL reduced the ARO liability related to the Stuart and Killen ash ponds and landfills by $27.6 million based on updated internal analyses that reduced estimated closure costs associated with these ash ponds and landfills. The remaining ARO liability related to Stuart and Killen is included in the AROs in the total liabilities of the disposal group classified as liabilities of discontinued operations and held-for-sale businesses in the balance sheets as of December 31, 2018 above. As these plants are no longer in service, the reduction to the ARO liability was also recorded as a credit to depreciation and amortization expense in the same amount. The credit to depreciation and amortization expense is included in operating and other expenses of discontinued operations for the year ended December 31, 2018 in the table above. Dispositions Beckjord Facility – 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 recognized a loss on the transfer of $11.7 million and made cash expenditures of $14.5 million , inclusive of cash expenditures for the transfer charges. The Beckjord Facility was retired in 2014, and, as such, the income / (loss) from continuing operations before income tax related to the Beckjord Facility was immaterial for the years ended December 31, 2018 , 2017 and 2016 , excluding the loss on transfer noted above. Prior to the transfer, the Beckjord Facility was included in the Utility segment. |
Generation Separation (Notes)
Generation Separation (Notes) | 12 Months Ended |
Dec. 31, 2018 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |
Discontinued Operations | Discontinued Operations 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, which resulted in a gain on sale of $14.0 million for the year ended December 31, 2017. On March 27, 2018, DPL and AES Ohio Generation completed the sale transaction of the Peaker assets to Kimura Power, LLC, which resulted in a loss on sale of $1.9 million for the year ended December 31, 2018. Further, on May 31, 2018, DPL and AES Ohio Generation retired the Stuart Station coal-fired and diesel-fired generating units and the Killen Station coal-fired generating unit and combustion turbine, as planned. Consequently, in the second quarter of 2018, DPL determined that the disposal of this group of components as a whole represents a strategic shift by us to exit generation, and, as such, qualifies to be presented as discontinued operations. Therefore, the results of operations and financial position for this group of components were reported as such in the Consolidated Statements of Operations and Consolidated Balance Sheets for all periods presented. Previously, on January 1, 2016, DPL closed on the sale of DPLER, its competitive retail business. The sale agreement was signed on December 28, 2015, and DPL received $75.5 million of restricted cash on December 31, 2015 for the sale. 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. As such, the results of operations of DPLER were also reported as discontinued operations in the Consolidated Statements of Operations for the year ended December 31, 2016. The following table summarizes the major categories of assets and liabilities at the dates indicated: $ in millions December 31, 2018 December 31, 2017 Restricted cash $ — $ 1.5 Accounts receivable, net 4.0 37.9 Inventories — 19.4 Taxes applicable to subsequent years 2.3 7.4 Other prepayments and current assets 2.4 17.4 Property, plant & equipment, net — 232.2 Intangible assets, net 5.3 5.5 Other deferred assets — 0.6 Total assets of the disposal group classified as assets of discontinued operations and held-for-sale businesses in the balance sheets $ 14.0 $ 321.9 Accounts payable $ 3.9 $ 25.1 Accrued taxes 3.1 6.3 Other current liabilities 5.2 30.0 Long-term debt (a) — 0.3 Deferred taxes (b) (39.8 ) (2.3 ) Taxes payable 2.3 7.4 Pension, retiree and other benefits 9.7 10.6 Asset retirement obligations 90.4 116.6 Other deferred credits 6.6 5.9 Total liabilities of the disposal group classified as liabilities of discontinued operations and held-for-sale businesses in the balance sheets $ 81.4 $ 199.9 (a) Long-term debt relates to capital leases. (b) Deferred taxes represent the tax asset position of the discontinued group of components, which were netted with liabilities on DPL prior to classification as discontinued operations. The following table summarizes the revenues, cost of revenues, operating and other expenses and income tax of discontinued operations for the periods indicated: Years ended December 31, $ in millions 2018 2017 2016 Revenues $ 158.6 $ 492.9 $ 593.0 Cost of revenues (74.3 ) (249.5 ) (349.6 ) Operating and other expenses (13.8 ) (195.0 ) (214.6 ) Fixed-asset impairment — (175.8 ) (835.2 ) Income / (loss) from discontinued operations 70.5 (127.4 ) (806.4 ) Gain / (loss) from disposal of discontinued operations (1.6 ) 14.0 49.2 Income tax expense / (benefit) from discontinued operations 30.0 (20.3 ) (257.2 ) Net income / (loss) from discontinued operations $ 38.9 $ (93.1 ) $ (500.0 ) Cash flows related to discontinued operations are included in our Consolidated Statements of Cash Flows. Cash flows from operating activities for discontinued operations were $(6.8) million , $126.8 million and $92.3 million for the years ended December 31, 2018, 2017 and 2016, respectively. Cash flows from investing activities for discontinued operations were $233.8 million , $51.8 million and $(56.8) million for the years ended December 31, 2018, 2017 and 2016, respectively. The PUCO authorized DP&L to maintain long-term debt of $750.0 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 interest expense is included in the discontinued operations above. The interest expense included in discontinued operations was $0.2 million and $0.5 million for the years December 31, 2017 and 2016, respectively. AROs of Discontinued Operations DPL's retired Stuart and Killen generating facilities continue to carry ARO liabilities consisting primarily of river intake and discharge structures, coal unloading facilities, landfills, and ash disposal facilities. In the fourth quarter of 2018, DPL reduced the ARO liability related to the Stuart and Killen ash ponds and landfills by $27.6 million based on updated internal analyses that reduced estimated closure costs associated with these ash ponds and landfills. The remaining ARO liability related to Stuart and Killen is included in the AROs in the total liabilities of the disposal group classified as liabilities of discontinued operations and held-for-sale businesses in the balance sheets as of December 31, 2018 above. As these plants are no longer in service, the reduction to the ARO liability was also recorded as a credit to depreciation and amortization expense in the same amount. The credit to depreciation and amortization expense is included in operating and other expenses of discontinued operations for the year ended December 31, 2018 in the table above. Dispositions Beckjord Facility – 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 recognized a loss on the transfer of $11.7 million and made cash expenditures of $14.5 million , inclusive of cash expenditures for the transfer charges. The Beckjord Facility was retired in 2014, and, as such, the income / (loss) from continuing operations before income tax related to the Beckjord Facility was immaterial for the years ended December 31, 2018 , 2017 and 2016 , excluding the loss on transfer noted above. Prior to the transfer, the Beckjord Facility was included in the Utility segment. |
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 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 and 2016. The following table summarizes the revenues, cost of revenues, operating and other expenses and income tax of discontinued operations for the periods indicated: Years ended December 31, $ in millions 2017 2016 Revenues $ 358.4 $ 557.9 Cost of revenues (191.6 ) (341.1 ) Operating and other expenses (156.8 ) (202.0 ) Fixed-asset impairment (66.3 ) (1,353.5 ) Loss from discontinued operations (56.3 ) (1,338.7 ) Income tax benefit from discontinued operations (15.9 ) (468.4 ) Net loss from discontinued operations $ (40.4 ) $ (870.3 ) In 2018, DP&L transferred additional deferred taxes to AES Ohio Generation under the provisions of SAB 118 through an equity transaction with DPL in the amount of $10.0 million . See Note 8 – Income Taxes for additional information. Cash flows related to discontinued operations are included in the Statements of Cash Flows. Cash flows from operating activities for discontinued operations were $21.8 million and $29.9 million for the years ended December 31, 2017 and 2016, respectively. Cash flows from investing activities for discontinued operations were $(3.5) million and $(39.0) million for the years ended December 31, 2017 and 2016, 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 interest expense is included in discontinued operations above. The interest expense included in discontinued operations was $0.2 million and $0.5 million for the years ended December 31, 2017 and 2016, respectively. Dispositions Beckjord Facility – 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 recognized a loss on the transfer of $12.4 million and made cash expenditures of $14.5 million , inclusive of cash expenditures for the transfer charges. The Beckjord Facility was retired in 2014, and, as such, the income / (loss) from continuing operations before income tax related to the Beckjord Facility was immaterial for the years ended December 31, 2018 , 2017 and 2016 , excluding the loss on transfer noted above. |
Assets and Liabilities Held-For
Assets and Liabilities Held-For-Sale and Dispositions (Notes) | 12 Months Ended |
Dec. 31, 2018 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |
Discontinued Operations | Discontinued Operations 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, which resulted in a gain on sale of $14.0 million for the year ended December 31, 2017. On March 27, 2018, DPL and AES Ohio Generation completed the sale transaction of the Peaker assets to Kimura Power, LLC, which resulted in a loss on sale of $1.9 million for the year ended December 31, 2018. Further, on May 31, 2018, DPL and AES Ohio Generation retired the Stuart Station coal-fired and diesel-fired generating units and the Killen Station coal-fired generating unit and combustion turbine, as planned. Consequently, in the second quarter of 2018, DPL determined that the disposal of this group of components as a whole represents a strategic shift by us to exit generation, and, as such, qualifies to be presented as discontinued operations. Therefore, the results of operations and financial position for this group of components were reported as such in the Consolidated Statements of Operations and Consolidated Balance Sheets for all periods presented. Previously, on January 1, 2016, DPL closed on the sale of DPLER, its competitive retail business. The sale agreement was signed on December 28, 2015, and DPL received $75.5 million of restricted cash on December 31, 2015 for the sale. 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. As such, the results of operations of DPLER were also reported as discontinued operations in the Consolidated Statements of Operations for the year ended December 31, 2016. The following table summarizes the major categories of assets and liabilities at the dates indicated: $ in millions December 31, 2018 December 31, 2017 Restricted cash $ — $ 1.5 Accounts receivable, net 4.0 37.9 Inventories — 19.4 Taxes applicable to subsequent years 2.3 7.4 Other prepayments and current assets 2.4 17.4 Property, plant & equipment, net — 232.2 Intangible assets, net 5.3 5.5 Other deferred assets — 0.6 Total assets of the disposal group classified as assets of discontinued operations and held-for-sale businesses in the balance sheets $ 14.0 $ 321.9 Accounts payable $ 3.9 $ 25.1 Accrued taxes 3.1 6.3 Other current liabilities 5.2 30.0 Long-term debt (a) — 0.3 Deferred taxes (b) (39.8 ) (2.3 ) Taxes payable 2.3 7.4 Pension, retiree and other benefits 9.7 10.6 Asset retirement obligations 90.4 116.6 Other deferred credits 6.6 5.9 Total liabilities of the disposal group classified as liabilities of discontinued operations and held-for-sale businesses in the balance sheets $ 81.4 $ 199.9 (a) Long-term debt relates to capital leases. (b) Deferred taxes represent the tax asset position of the discontinued group of components, which were netted with liabilities on DPL prior to classification as discontinued operations. The following table summarizes the revenues, cost of revenues, operating and other expenses and income tax of discontinued operations for the periods indicated: Years ended December 31, $ in millions 2018 2017 2016 Revenues $ 158.6 $ 492.9 $ 593.0 Cost of revenues (74.3 ) (249.5 ) (349.6 ) Operating and other expenses (13.8 ) (195.0 ) (214.6 ) Fixed-asset impairment — (175.8 ) (835.2 ) Income / (loss) from discontinued operations 70.5 (127.4 ) (806.4 ) Gain / (loss) from disposal of discontinued operations (1.6 ) 14.0 49.2 Income tax expense / (benefit) from discontinued operations 30.0 (20.3 ) (257.2 ) Net income / (loss) from discontinued operations $ 38.9 $ (93.1 ) $ (500.0 ) Cash flows related to discontinued operations are included in our Consolidated Statements of Cash Flows. Cash flows from operating activities for discontinued operations were $(6.8) million , $126.8 million and $92.3 million for the years ended December 31, 2018, 2017 and 2016, respectively. Cash flows from investing activities for discontinued operations were $233.8 million , $51.8 million and $(56.8) million for the years ended December 31, 2018, 2017 and 2016, respectively. The PUCO authorized DP&L to maintain long-term debt of $750.0 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 interest expense is included in the discontinued operations above. The interest expense included in discontinued operations was $0.2 million and $0.5 million for the years December 31, 2017 and 2016, respectively. AROs of Discontinued Operations DPL's retired Stuart and Killen generating facilities continue to carry ARO liabilities consisting primarily of river intake and discharge structures, coal unloading facilities, landfills, and ash disposal facilities. In the fourth quarter of 2018, DPL reduced the ARO liability related to the Stuart and Killen ash ponds and landfills by $27.6 million based on updated internal analyses that reduced estimated closure costs associated with these ash ponds and landfills. The remaining ARO liability related to Stuart and Killen is included in the AROs in the total liabilities of the disposal group classified as liabilities of discontinued operations and held-for-sale businesses in the balance sheets as of December 31, 2018 above. As these plants are no longer in service, the reduction to the ARO liability was also recorded as a credit to depreciation and amortization expense in the same amount. The credit to depreciation and amortization expense is included in operating and other expenses of discontinued operations for the year ended December 31, 2018 in the table above. Dispositions Beckjord Facility – 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 recognized a loss on the transfer of $11.7 million and made cash expenditures of $14.5 million , inclusive of cash expenditures for the transfer charges. The Beckjord Facility was retired in 2014, and, as such, the income / (loss) from continuing operations before income tax related to the Beckjord Facility was immaterial for the years ended December 31, 2018 , 2017 and 2016 , excluding the loss on transfer noted above. Prior to the transfer, the Beckjord Facility was included in the Utility segment. |
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 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 and 2016. The following table summarizes the revenues, cost of revenues, operating and other expenses and income tax of discontinued operations for the periods indicated: Years ended December 31, $ in millions 2017 2016 Revenues $ 358.4 $ 557.9 Cost of revenues (191.6 ) (341.1 ) Operating and other expenses (156.8 ) (202.0 ) Fixed-asset impairment (66.3 ) (1,353.5 ) Loss from discontinued operations (56.3 ) (1,338.7 ) Income tax benefit from discontinued operations (15.9 ) (468.4 ) Net loss from discontinued operations $ (40.4 ) $ (870.3 ) In 2018, DP&L transferred additional deferred taxes to AES Ohio Generation under the provisions of SAB 118 through an equity transaction with DPL in the amount of $10.0 million . See Note 8 – Income Taxes for additional information. Cash flows related to discontinued operations are included in the Statements of Cash Flows. Cash flows from operating activities for discontinued operations were $21.8 million and $29.9 million for the years ended December 31, 2017 and 2016, respectively. Cash flows from investing activities for discontinued operations were $(3.5) million and $(39.0) million for the years ended December 31, 2017 and 2016, 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 interest expense is included in discontinued operations above. The interest expense included in discontinued operations was $0.2 million and $0.5 million for the years ended December 31, 2017 and 2016, respectively. Dispositions Beckjord Facility – 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 recognized a loss on the transfer of $12.4 million and made cash expenditures of $14.5 million , inclusive of cash expenditures for the transfer charges. The Beckjord Facility was retired in 2014, and, as such, the income / (loss) from continuing operations before income tax related to the Beckjord Facility was immaterial for the years ended December 31, 2018 , 2017 and 2016 , excluding the loss on transfer noted above. |
Fixed Asset Impairment
Fixed Asset Impairment | 12 Months Ended |
Dec. 31, 2018 | |
Entity Information [Line Items] | |
Fixed-asset Impairment | Fixed-asset impairments During the fourth quarter of 2016, we tested the recoverability of our long-lived coal-fired generation assets. 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. We performed a long-lived asset impairment analysis for the Conesville asset group and determined that its carrying amount was not recoverable. The Conesville coal-fired facility asset group was determined to have a fair value of $1.1 million using the income approach. As a result, DPL recognized a total pre-tax asset impairment expense of $23.9 million . During the year ended December 31, 2018 , DPL recognized a total pre-tax asset impairment expense of $2.8 million for the Conesville asset group, as it was determined that additional amounts capitalized in 2018 were not recoverable. |
Schedule II Valuation And Quali
Schedule II Valuation And Qualifying Accounts | 12 Months Ended |
Dec. 31, 2018 | |
Schedule II Valuation And Qualifying Accounts | Schedule II DPL Inc. VALUATION AND QUALIFYING ACCOUNTS For each of the three years ended December 31, 2018 $ in thousands Description Balance at Beginning of Period Additions Deductions (a) Balance at End of Period Year ended December 31, 2018 Deducted from accounts receivable - Provision for uncollectible accounts $ 1,053 $ 3,411 $ 3,574 $ 890 Deducted from deferred tax assets - Valuation allowance for deferred tax assets (b) $ 36,328 $ 1,539 $ 8,794 $ 29,073 Year ended December 31, 2017 Deducted from accounts receivable - Provision for uncollectible accounts $ 1,159 $ 3,141 $ 3,247 $ 1,053 Deducted from deferred tax assets - Valuation allowance for deferred tax assets (b) $ 38,266 $ 4,383 $ 6,321 $ 36,328 Year ended December 31, 2016 Deducted from accounts receivable - Provision for uncollectible accounts $ 835 $ 4,113 $ 3,789 $ 1,159 Deducted from deferred tax assets - Valuation allowance for deferred tax assets (b) $ 39,874 $ — $ 1,608 $ 38,266 (a) Amounts written off, net of recoveries of accounts previously written off (b) Balances and activity for valuation allowances for deferred tax assets includes that of amounts presented within both the " Deferred taxes" line and the "Non-current liabilities of discontinued operations and held-for-sale businesses" line on DPL’s Consolidated Balance Sheets. THE DAYTON POWER AND LIGHT COMPANY VALUATION AND QUALIFYING ACCOUNTS For each of the three years ended December 31, 2018 $ in thousands Description Balance at Beginning of Period Additions Deductions (a) Balance at End of Period Year ended December 31, 2018 Deducted from accounts receivable - Provision for uncollectible accounts $ 1,053 $ 3,411 $ 3,574 $ 890 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 |
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, 2018 $ in thousands Description Balance at Beginning of Period Additions Deductions (a) Balance at End of Period Year ended December 31, 2018 Deducted from accounts receivable - Provision for uncollectible accounts $ 1,053 $ 3,411 $ 3,574 $ 890 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 (a) Amounts written off, net of recoveries of accounts previously written off |
Overview and Summary of Signi_2
Overview and Summary of Significant Accounting Policies (Policy) | 12 Months Ended |
Dec. 31, 2018 | |
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 one reportable segment, the Utility segment. See Note 13 – Business Segments for more information relating to our reportable segment. 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, DPL's wholly-owned subsidiary , 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 525,000 customers located in West Central Ohio. DP&L provides 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 all of the generation for its SSO customers through a competitive bid process. Through September 30, 2017, DP&L owned undivided interests in multiple 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, excluding the Beckjord Facility and Hutchings EGU, 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. DPL’s other primary subsidiaries include MVIC and AES Ohio Generation. MVIC is our captive insurance company that provides insurance services to DPL and our subsidiaries. AES Ohio Generation owns an undivided interest in Conesville Unit 4 . AES Ohio Generation sells all of its energy and capacity into the wholesale market. DPL's subsidiaries are wholly-owned. 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 March 27, 2018, DPL and AES Ohio Generation completed the sale of their Peaker assets to Kimura Power, LLC. Further, on May 31, 2018, DPL and AES Ohio Generation retired the Stuart Station coal-fired and diesel-fired generating units and the Killen Station coal-fired generating unit and combustion turbine, as planned. See Note 15 – Discontinued Operations for additional information. 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 or overcollections of riders. DPL and its subsidiaries employed 659 people at January 31, 2019 , of which 647 were employed by DP&L. Approximately 57% of all DPL employees are under a collective bargaining agreement. |
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. Through June 2018, DP&L had undivided ownership interests in numerous transmission facilities. These undivided interests in jointly-owned facilities were accounted for on a pro rata basis in the Consolidated Financial Statements. In June 2018, DP&L closed on a transmission asset transaction with Duke and AEP, where ownership stakes in certain previously co-owned transmission assets were exchanged to eliminate co-ownership. Each previously co-owned transmission asset became wholly-owned by one of DP&L , Duke or AEP after the transaction. 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 assets 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 Consolidated 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 15 – 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; 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. Revenue is recognized upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. 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. The power sales and purchases within DP&L’s service territory are reported on a net hourly basis as revenues or purchased power on our Consolidated Statements of Operations. We record expenses when purchased electricity is received and when expenses are incurred. All of the power produced at the generation station is sold to an RTO. We record expenses when purchased electricity is received and when expenses are incurred. For additional information, see Note 14 – Revenue . |
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 our jointly-held station 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 $0.5 million , $1.7 million and $2.1 million in the years ended December 31, 2018 , 2017 and 2016 , 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. |
Repairs and Maintenance | Costs associated with maintenance activities 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 4.3% in 2018 , 5.0% in 2017 and 6.1% in 2016 (including property classified in non-current assets of discontinued operations and held-for-sale businesses in 2017 and 2016). Depreciation expense was $66.5 million , $70.4 million and $67.0 million for the years ended December 31, 2018 , 2017 and 2016 , 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 and materials and supplies used for utility operations. |
Intangibles | Software is amortized over seven years . Amortization expense was $6.6 million , $5.7 million and $6.6 million for the years ended December 31, 2018 , 2017 and 2016 , respectively. The estimated amortization expense of this internal-use software over the next five years is $15.0 million ( $4.2 million in 2019, $3.2 million in 2020, $3.0 million in 2021, $2.6 million in 2022 and $2.0 million in 2023 ). |
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 or liability with a corresponding deferred tax liability or asset. Investment tax credits that reduced federal income taxes in the years they arose have been deferred and are being amortized to income over the useful lives of the properties in accordance with regulatory treatment . See Note 3 – Regulatory Matters for additional information. DPL and its subsidiaries file U.S. federal income tax returns as part of the consolidated U.S. income tax return filed by AES. The consolidated tax liability is allocated to each subsidiary based on the separate return method which is specified in our tax allocation agreement and which provides a consistent, systematic and rational approach . See Note 8 – Income Taxes for additional information. |
Financial Instruments | Our Master Trust investments in debt and equity financial instruments of publicly traded entities are classified as equity investments. These equity securities are carried at fair value and unrealized gains and losses on these securities are recorded in Other income. As these financial instruments are held to be used for the benefit of employees participating in employee benefit plans and are not used for general operating purposes, they are classified as non-current in Other deferred assets on the Consolidated Balance Sheets. |
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 15 – Discontinued Operations 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 Consolidated Statements of Operations. The amounts for the years ended December 31, 2018 , 2017 and 2016 , were $51.7 million , $49.4 million and $50.9 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 interest rate hedges to manage the interest rate risk of our variable rate debt. 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 and our subsidiaries 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 $4.1 million and $3.0 million at December 31, 2018 and 2017 , 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 $4.3 million and $4.4 million at December 31, 2018 and 2017 , 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 from actuarial gains or losses related to our regulated operations, that would otherwise be recognized in AOCI, recorded as a regulatory asset as this can be recovered through future rates. Such changes that are not related to our regulated operations are recognized in AOCI. 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. See Note 9 – 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 12 – Related Party Transactions for more information on Related Party Transactions. |
Recently Issued Accounting Standards | New accounting pronouncements adopted in 2018 The following table provides a brief description of recently adopted accounting pronouncements that had an impact on our consolidated financial statements. Accounting pronouncements not listed below were assessed and determined to be either not applicable or did not 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 2018-15, Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract This standard aligns the accounting for implementation costs incurred for a cloud computing arrangement that is a service with the requirement for capitalizing implementation costs associated with developing or obtaining internal-use software. October 1, 2018 We elected to early-adopt this standard on a prospective basis, effective for fiscal year 2018. The adoption of this standard did not have a material impact on our financial statements. 2018-14, Compensation— Retirement Benefits — Defined Benefit Plans — General (Subtopic 715-20): Disclosure Framework This standard modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. Early adoption elected, January 1, 2018 Impact limited to changes in financial statement disclosures. 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 costs associated with defined benefit plans and updates the guidance so that only the service cost component will be eligible for capitalization. January 1, 2018 For the years ended December 31, 2017 and 2016 we reclassified non-service pension costs from Operating expenses to Other expense of $2.2 million and $3.2 million, respectively. 2016-18, Statement of Cash Flows (Topic 230): 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 For the years ended December 31, 2017 and 2016, we reclassified from "Net cash used in investing activities" to "Net increase / (decrease) in cash, cash equivalents and restricted cash" $27.1 million and ($11.8) million, respectively. 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities The standard significantly revises an entity’s accounting related to (1) classification and measurement of investments in equity securities and (2) the presentation of certain fair value changes for financial liabilities measured at fair value. It also amends certain disclosures of financial instruments. Transition method: modified retrospective. Prospective for equity investments without readily determinable fair value. January 1, 2018 We adopted this standard January 1, 2018. At that date, we transferred $1.6 million ($1.0 million net of tax) of unrealized gains from AOCI to Accumulated Deficit. 2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-10, 2017-13, Revenue from Contracts with Customers (Topic 606) See discussion of the ASU below. January 1, 2018 See impact upon adoption of the standard below. Adoption of FASC Topic 606, "Revenue from Contracts with Customers" On January 1, 2018, we adopted ASU 2014-09, "Revenue from Contracts with Customers", and its subsequent corresponding updates ("FASC 606"). The core principle of this standard 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. We applied the modified retrospective method of adoption to those contracts which were not completed as of January 1, 2018. Results for reporting periods beginning January 1, 2018 are presented under FASC 606, while prior period amounts were not adjusted and continue to be reported in accordance with our historic accounting under the previous revenue recognition standard. For contracts that were modified before January 1, 2018, we have not retrospectively restated the contracts for modifications. We instead reflected the aggregate effect of all modifications when identifying the satisfied and unsatisfied performance obligations, determining the transaction price and allocating the transaction price. We do not expect the adoption of the new revenue standard to have a material impact to our net income on an ongoing basis. There was no cumulative effect to our January 1, 2018 Consolidated Balance Sheet resulting from the adoption of FASC 606. New accounting pronouncements issued but not yet effective - The following table provides a brief description of recent accounting pronouncements that could have a material impact on our consolidated financial statements. Accounting pronouncements not listed below were assessed and determined to be either not applicable or are expected to have no material impact on our consolidated financial statements. Accounting Standard Description Date of Adoption Effect on the financial statements upon adoption 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 do not expect any impact on our consolidated financial statements upon adoption of the standard on January 1, 2019. 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 in the period in which it settles. Transition method: modified retrospective with the cumulative effect adjustment recorded to the opening balance of retained earnings as of the initial application date. Prospective for presentation and disclosures. January 1, 2019. Early adoption is permitted. We are currently evaluating the impact of adopting the standard on our consolidated financial statements. 2018-19, 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. For trade and other receivables, held-to-maturity debt securities, loans and other instruments, entities will be required to use a new forward-looking "expected loss" model that generally will result in the earlier recognition of allowance for losses. For available-for-sale debt securities with unrealized losses, entities will measure credit losses as it is done today, except that the losses will be recognized as an allowance rather than a reduction in the amortized cost of the securities. Transition method: various. January 1, 2020. Early adoption is permitted only as of January 1, 2019. We are currently evaluating the impact of adopting the standard on our consolidated financial statements. 2016-02, 2018-01, 2018-10, 2018-11, 2018-20 See discussion of the ASU below. January 1, 2019. Early adoption is permitted. We have adopted the standard on January 1, 2019; see below for the evaluation of the impact of its adoption on our consolidated financial statements. Adoption of FASC Topic 842, "Leases" 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 must be adopted using a modified retrospective approach. The FASB has provided an optional transition method, which we have elected, that allows entities to continue to apply the guidance in FASC 840 Leases to the comparative periods presented in the year of adoption. Under this transition method, we will apply the transition provisions starting on January 1, 2019. We have elected to apply a package of practical expedients that allow lessees and lessors 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. We have also elected to apply an optional transition practical expedient for land easements that allows an entity to continue applying its current accounting policy for all land easements that exist before the standard’s effective date that were not previously accounted for under FASC 840. We 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 assets and related liabilities. Additionally, the implementation team has been working on the configuration of a lease accounting tool that will support the implementation and the subsequent accounting. The implementation team has also evaluated changes to our business processes, systems and controls to support recognition and disclosure under the new standard. Under FASC 842, it is expected that fewer contracts will contain a lease. However, due to the elimination of the 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 includes the fair value of the plant after the contract period but does not include any variable payments such as margin on the sale of energy. Therefore, the lease receivable could be significantly different 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 asset is recognized as a gain/loss at lease commencement. The adoption of FASC 842 did not have a material impact on our consolidated financial statements. |
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 525,000 customers located in West Central Ohio. DP&L provides 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 all of the generation for its SSO customers through a competitive bid process. Through September 30, 2017, DP&L owned undivided interests in multiple 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, excluding the Beckjord Facility and Hutchings EGU, 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. 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. 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 or overcollections of riders. DP&L employed 647 people at January 31, 2019 . Approximately 58% of all employees are under a collective bargaining agreement. |
Financial Statement Presentation | DP&L does not have any subsidiaries. Through June 2018, DP&L had undivided ownership interests in numerous transmission facilities. These undivided interests in jointly-owned facilities were accounted for on a pro rata basis in the Financial Statements. In June 2018, DP&L closed on a transmission asset transaction with Duke and AEP, where ownership stakes in certain previously co-owned transmission assets were exchanged to eliminate co-ownership. Each previously co-owned transmission asset became wholly-owned by one of DP&L , Duke or AEP after the transaction. 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. |
Discontinued Operations, Policy [Policy Text Block] | Discontinued operations reporting occurs only when the disposal of a business or a group of assets 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 14 – Generation Separation for further information. Generation Separation With the transfer of DP&L's generation assets to an affiliate (see Note 14 – 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 and 2016 and in the notes to the financial statements. 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 interest expense is included in discontinued operations above. The interest expense included in discontinued operations was $0.2 million and $0.5 million for the years ended December 31, 2017 and 2016, 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. Revenue is recognized upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. 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. For additional information, see Note 13 – Revenue |
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 $0.5 million , $1.5 million and $2.0 million for the years ended December 31, 2018 , 2017 and 2016 , 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 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 3.0% in 2018 , 3.4% in 2017 and 4.6% in 2016 . Depreciation expense was $68.2 million , $69.6 million and $64.3 million for the years ended December 31, 2018 , 2017 and 2016 , 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 Amortization expense was $6.3 million , $5.7 million and $6.7 million for the years ended December 31, 2018 , 2017 and 2016 , respectively. The estimated amortization expense of this internal-use software over the next five years is $11.1 million ( $3.5 million in 2019, $2.4 million in 2020, $2.2 million in 2021, $1.8 million in 2022 and $1.2 million in 2023 ). |
Income Taxes | Income taxes payable, which are includable in allowable costs for ratemaking purposes in future years, are recorded as regulatory assets or liability with a corresponding deferred tax liability or asset. 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 | Our Master Trust investments in debt and equity financial instruments of publicly traded entities are classified as equity investments. These equity securities are carried at fair value and unrealized gains and losses on these securities are recorded in Other income. As these financial instruments are held to be used for the benefit of employees participating in employee benefit plans and are not used for general operating purposes, they are classified as non-current in Other deferred assets on the Consolidated Balance Sheets. |
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 14 – Generation Separation 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, 2018 , 2017 and 2016 were $51.7 million , $49.4 million and $50.9 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 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. The following table provides a summary of cash, cash equivalents, and restricted cash amounts reported on the Balance Sheet that reconcile to the total of such amounts as shown on the Statements of Cash Flows: $ in millions December 31, 2018 December 31, 2017 Cash and cash equivalents $ 45.0 $ 5.2 Restricted cash 21.2 0.4 Cash, Cash Equivalents, and Restricted Cash, End of Period $ 66.2 $ 5.6 |
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 interest rate hedges to manage the interest rate risk of our variable rate debt. 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 | and other DPL subsidiaries for workers’ compensation, general liability, and property damage on an ongoing basis. DP&L is responsible for claims 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 third-party providers of approximately $4.3 million and $4.4 million at December 31, 2018 and 2017 , 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. 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 adopted in 2018 The following table provides a brief description of recently adopted accounting pronouncements that had an impact on our consolidated financial statements. Accounting pronouncements not listed below were assessed and determined to be either not applicable or did not 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 2018-15, Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract This standard aligns the accounting for implementation costs incurred for a cloud computing arrangement that is a service with the requirement for capitalizing implementation costs associated with developing or obtaining internal-use software. October 1, 2018 We elected to early-adopt this standard on a prospective basis, effective for fiscal year 2018. The adoption of this standard did not have a material impact on our financial statements. 2018-14, Compensation— Retirement Benefits — Defined Benefit Plans — General (Subtopic 715-20): Disclosure Framework This standard modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. Early adoption elected, January 1, 2018 Impact limited to changes in financial statement disclosures. 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 costs associated with defined benefit plans and updates the guidance so that only the service cost component will be eligible for capitalization. January 1, 2018 For the years ended December 31, 2017 and 2016 we reclassified non-service pension costs from Operating expenses to Other expense of ($1.5) million and ($0.9) million, respectively. 2016-18, Statement of Cash Flows (Topic 230): 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 For the years ended December 31, 2017 and 2016, we reclassified from "Net cash used in investing activities" to "Net increase / (decrease) in cash, cash equivalents and restricted cash" $26.6 million and ($11.9) million, respectively. 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities The standard significantly revises an entity’s accounting related to (1) classification and measurement of investments in equity securities and (2) the presentation of certain fair value changes for financial liabilities measured at fair value. It also amends certain disclosures of financial instruments. January 1, 2018 We adopted this standard January 1, 2018. At that date, we transferred $1.7 million ($1.1 million net of tax) of unrealized gains from AOCI to Retained Earnings. 2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-10, 2017-13, Revenue from Contracts with Customers (Topic 606) See discussion of the ASU below. January 1, 2018 See impact upon adoption of the standard below. Adoption of FASC Topic 606, "Revenue from Contracts with Customers" On January 1, 2018, we adopted ASU 2014-09, "Revenue from Contracts with Customers", and its subsequent corresponding updates ("FASC 606"). The core principle of this standard 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. We applied the modified retrospective method of adoption to those contracts which were not completed as of January 1, 2018. Results for reporting periods beginning January 1, 2018 are presented under FASC 606, while prior period amounts were not adjusted and continue to be reported in accordance with our historic accounting under the previous revenue recognition standard. For contracts that were modified before January 1, 2018, we have not retrospectively restated the contracts for modifications. We instead reflected the aggregate effect of all modifications when identifying the satisfied and unsatisfied performance obligations, determining the transaction price and allocating the transaction price. We do not expect the adoption of the new revenue standard to have a material impact to our net income on an ongoing basis. There was no cumulative effect to our January 1, 2018 Balance Sheet resulting from the adoption of FASC 606. New accounting pronouncements issued but not yet effective - The following table provides a brief description of recent accounting pronouncements that could have a material impact on our financial statements. Accounting pronouncements not listed below were assessed and determined to be either not applicable or are expected to have no material impact on our financial statements. Accounting Standard Description Date of Adoption Effect on the financial statements upon adoption New Accounting Standards Issued but Not Yet Effective 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 do not expect any impact on our financial statements upon adoption of the standard on January 1, 2019. 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 in the period in which it settles. January 1, 2019. Early adoption is permitted. We are currently evaluating the impact of adopting the standard on our financial statements. 2018-19, 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. For trade and other receivables, held-to-maturity debt securities, loans and other instruments, entities will be required to use a new forward-looking "expected loss" model that generally will result in the earlier recognition of allowance for losses. For available-for-sale debt securities with unrealized losses, entities will measure credit losses as it is done today, except that the losses will be recognized as an allowance rather than a reduction in the amortized cost of the securities. 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, 2018-01, 2018-10, 2018-11, 2018-20 See discussion of the ASU below. January 1, 2019. Early adoption is permitted. We will adopt the standard on January 1, 2019; see below for the evaluation of the impact of its adoption on our financial statements. Adoption of FASC Topic 842, "Leases" 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 must be adopted using a modified retrospective approach. The FASB has provided an optional transition method, which we have elected, that allows entities to continue to apply the guidance in FASC 840 Leases to the comparative periods presented in the year of adoption. Under this transition method, we will apply the transition provisions starting on January 1, 2019. We have elected to apply a package of practical expedients that allow lessees and lessors 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. We have also elected to apply an optional transition practical expedient for land easements that allows an entity to continue applying its current accounting policy for all land easements that exist before the standard’s effective date that were not previously accounted for under FASC 840. We 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 assets and related liabilities. Additionally, the implementation team has been working on the configuration of a lease accounting tool that will support the implementation and the subsequent accounting. The implementation team has also evaluated changes to our business processes, systems and controls to support recognition and disclosure under the new standard. Under FASC 842, it is expected that fewer contracts will contain a lease. However, due to the elimination of the 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 includes the fair value of the plant after the contract period but does not include any variable payments such as margin on the sale of energy. Therefore, the lease receivable could be significantly different 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 asset is recognized as a gain/loss at lease commencement. The adoption of FASC 842 did not have a material impact on our financial statements. |
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 an unconsolidated subsidiary. The Trust holds mandatorily redeemable trust capital securities. The investment in the Trust, which amounts to $0.2 million and $0.3 million at December 31, 2018 and 2017 , 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, 2018 and 2017 , respectively, that was established upon the Trust’s deconsolidation in 2003. See Note 7 – Long-term 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, 2018 | |
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 assets 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 Consolidated 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 15 – 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 assets 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 14 – Generation Separation for further information. Generation Separation With the transfer of DP&L's generation assets to an affiliate (see Note 14 – 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 and 2016 and in the notes to the financial statements. 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 interest expense is included in discontinued operations above. The interest expense included in discontinued operations was $0.2 million and $0.5 million for the years ended December 31, 2017 and 2016, respectively. |
Overview and Summary of Signi_3
Overview and Summary of Significant Accounting Policies Overview and Summary of Significant Accounting Polices (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Schedule of Cash and Cash Equivalents [Table Text Block] | The following table provides a summary of cash, cash equivalents, and restricted cash amounts reported on the Consolidated Balance Sheet that reconcile to the total of such amounts as shown on the Consolidated Statements of Cash Flows: $ in millions December 31, 2018 December 31, 2017 Cash and cash equivalents $ 90.5 $ 24.5 Restricted cash 21.2 0.4 Cash, Cash Equivalents, and Restricted Cash, End of Period $ 111.7 $ 24.9 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Schedule of Cash and Cash Equivalents [Table Text Block] | The following table provides a summary of cash, cash equivalents, and restricted cash amounts reported on the Balance Sheet that reconcile to the total of such amounts as shown on the Statements of Cash Flows: $ in millions December 31, 2018 December 31, 2017 Cash and cash equivalents $ 45.0 $ 5.2 Restricted cash 21.2 0.4 Cash, Cash Equivalents, and Restricted Cash, End of Period $ 66.2 $ 5.6 |
Supplemental Financial Inform_2
Supplemental Financial Information (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Supplemental Financial Information [Line Items] | |
Supplemental Financial Information | December 31, $ in millions 2018 2017 Accounts receivable, net Customer receivables $ 55.8 $ 45.2 Unbilled revenue 16.8 18.0 Due from PJM transmission enhancement settlement (a) 16.5 — Other 2.3 2.5 Provisions for uncollectible accounts (0.9 ) (1.1 ) Total accounts receivable, net $ 90.5 $ 64.6 Inventories, at average cost Fuel and limestone $ 1.9 $ 4.1 Materials and supplies 8.3 8.1 Other 0.5 0.5 Total inventories, at average cost $ 10.7 $ 12.7 |
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, 2018 , 2017 and 2016 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 2018 2017 2016 Gains and losses on equity securities (Note 5): Other deductions $ — $ (0.1 ) $ — Income tax expense — — — Net of income taxes — (0.1 ) — Gains and losses on cash flow hedges (Note 6): Interest expense (1.2 ) (1.0 ) (1.0 ) Income tax benefit 0.4 0.3 0.5 Net of income taxes (0.8 ) (0.7 ) (0.5 ) Gain / (loss) from discontinued operations 4.4 (11.4 ) (45.4 ) Tax benefit / (expense) from discontinued operations (1.2 ) 4.1 16.2 Net of income taxes 3.2 (7.3 ) (29.2 ) Amortization of defined benefit pension items (Note 9): Other income 0.8 1.5 1.6 Income tax expense (0.2 ) (0.5 ) (0.6 ) Net of income taxes 0.6 1.0 1.0 Total reclassifications for the period, net of income taxes $ 3.0 $ (7.1 ) $ (28.7 ) |
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, 2018 and 2017 are as follows: $ in millions Gains / (losses) on equity securities Gains / (losses) on cash flow hedges Change in unfunded pension obligation Total 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 Other comprehensive loss before reclassifications — (0.1 ) (0.5 ) (0.6 ) Amounts reclassified from accumulated other comprehensive income to earnings — 2.4 0.6 3.0 Net current period other comprehensive income — 2.3 0.1 2.4 Amounts reclassified from accumulated other comprehensive income to accumulated deficit (a) (1.0 ) — — (1.0 ) Balance at December 31, 2018 $ — $ 17.0 $ (14.8 ) $ 2.2 (a) ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” was effective as of January 1, 2018. This ASU requires the change in the fair value of equity instruments to be recorded in income rather than in OCI. Equity Instruments were defined to include all mutual funds, regardless of the underlying investments. Therefore, as of January 1, 2018, AOCI of $1.6 million ( $1.0 million net of tax) was reversed to Accumulated Deficit. |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Supplemental Financial Information [Line Items] | |
Supplemental Financial Information | Supplemental Financial Information December 31, $ in millions 2018 2017 Accounts receivable, net Customer receivables $ 53.3 $ 44.2 Unbilled revenue 16.8 18.0 Amounts due from partners in jointly-owned stations — 5.0 Due from PJM transmission enhancement settlement (a) 16.5 — Due from affiliates 2.3 0.6 Other 2.4 4.1 Provisions for uncollectible accounts (0.9 ) (1.1 ) Total accounts receivable, net $ 90.4 $ 70.8 Inventories, at average cost Materials and supplies $ 7.1 $ 6.9 Other 0.6 0.4 Total inventories, at average cost $ 7.7 $ 7.3 (a) - See Note 3 – Regulatory Matters for more information. |
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, 2018 , 2017 and 2016 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 2018 2017 2016 Gains and losses on equity securities activity (Note 5): Other deductions $ — $ (0.1 ) $ — Income tax expense — — — Net of income taxes — (0.1 ) — Gains and losses on cash flow hedges (Note 6): Interest expense (1.1 ) (0.9 ) (1.0 ) Income tax benefit 0.4 0.2 0.2 Net of income taxes (0.7 ) (0.7 ) (0.8 ) Loss from discontinued operations — (8.5 ) (45.4 ) Income tax benefit from discontinued operations — 3.0 16.2 Net of income taxes — (5.5 ) (29.2 ) Amortization of defined benefit pension items (Note 9): Other income 4.3 6.8 7.7 Income tax expense (1.0 ) (2.3 ) (1.8 ) Net of income taxes 3.3 4.5 5.9 Total reclassifications for the period, net of income taxes $ 2.6 $ (1.8 ) $ (24.1 ) |
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, 2018 and 2017 are as follows: $ in millions Gains / (losses) on equity securities Gains / (losses) on cash flow hedges Change in unfunded pension obligation Total 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 ) Other comprehensive loss before reclassifications — (0.1 ) (0.5 ) (0.6 ) Amounts reclassified from accumulated other comprehensive income / (loss) to earnings — (0.7 ) 3.3 2.6 Net current period other comprehensive income / (loss) — (0.8 ) 2.8 2.0 Amounts reclassified from accumulated other comprehensive income to accumulated deficit (a) (1.1 ) — — (1.1 ) Balance at December 31, 2018 $ — $ 0.6 $ (35.9 ) $ (35.3 ) (a) ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” was effective as of January 1, 2018. This ASU requires the change in the fair value of equity instruments to be recorded in income rather than in OCI. Equity Instruments were defined to include all mutual funds, regardless of the underlying investments. |
Regulatory Matters (Tables)
Regulatory Matters (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Schedule of Regulatory Assets and Liabilities [Table Text Block] | The following table presents DPL’s Regulatory assets and liabilities: Type of Recovery Amortization Through December 31, $ in millions 2018 2017 Regulatory assets, current: Undercollections to be collected through rate riders A/B 2019 $ 40.5 $ 23.9 Rate case expenses being recovered in base rates B 2019 0.6 — Total regulatory assets, current 41.1 23.9 Regulatory assets, non-current: Pension benefits B Ongoing 87.5 92.4 Unrecovered OVEC charges C Undetermined 28.7 27.8 Fuel costs B 2020 3.3 9.3 Regulatory compliance costs B 2020 6.1 9.2 Smart grid and AMI costs B Undetermined 8.5 7.3 Unamortized loss on reacquired debt B Various 6.0 7.0 Deferred storm costs A Undetermined 4.7 2.1 Deferred vegetation management and other A/B Undetermined 7.8 8.1 Total regulatory assets, non-current 152.6 163.2 Total regulatory assets $ 193.7 $ 187.1 Regulatory liabilities, current: Overcollection of costs to be refunded through rate riders A/B 2019 $ 34.9 $ 14.8 Total regulatory liabilities, current 34.9 14.8 Regulatory liabilities, non-current: Estimated costs of removal - regulated property Not Applicable 139.1 132.8 Deferred income taxes payable through rates Various 116.3 83.4 PJM transmission enhancement settlement A 2025 16.9 — Postretirement benefits B Ongoing 6.0 5.0 Total regulatory liabilities, non-current 278.3 221.2 Total regulatory liabilities $ 313.2 $ 236.0 A – Recovery of incurred costs plus rate of return. B – Recovery of incurred costs without a rate of return. C – Recovery not yet determined, but recovery is probable of occurring in future rate proceedings. |
Subsidiaries [Member] | |
Schedule of Regulatory Assets and Liabilities [Table Text Block] | The following table presents DP&L’s Regulatory assets and liabilities: Type of Recovery Amortization Through December 31, $ in millions 2018 2017 Regulatory assets, current: Undercollections to be collected through rate riders A/B 2019 $ 40.5 $ 23.9 Rate case expenses being recovered in base rates B 2019 0.6 — Total regulatory assets, current 41.1 23.9 Regulatory assets, non-current: Pension benefits B Ongoing 87.5 92.4 Unrecovered OVEC charges C Undetermined 28.7 27.8 Fuel costs B 2020 3.3 9.3 Regulatory compliance costs B 2020 6.1 9.2 Smart grid and AMI costs B Undetermined 8.5 7.3 Unamortized loss on reacquired debt B Various 6.0 7.0 Deferred storm costs A Undetermined 4.7 2.1 Deferred vegetation management and other A/B Undetermined 7.8 8.1 Total regulatory assets, non-current 152.6 163.2 Total regulatory assets $ 193.7 $ 187.1 Regulatory liabilities, current: Overcollection of costs to be refunded through rate riders A/B 2018 $ 34.9 $ 14.8 Total regulatory liabilities, current 34.9 14.8 Regulatory liabilities, non-current: Estimated costs of removal - regulated property Not Applicable 139.1 132.8 Deferred income taxes payable through rates Various 116.3 83.4 PJM transmission enhancement settlement A 2025 16.9 — Postretirement benefits B Ongoing 6.0 5.0 Total regulatory liabilities, non-current 278.3 221.2 Total regulatory liabilities $ 313.2 $ 236.0 A – Recovery of incurred costs plus rate of return. B – Recovery of incurred costs without a rate of return. C – 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, 2018 | |
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, 2018 and 2017 : December 31, 2018 December 31, 2017 $ in millions Composite Rate Composite Rate (a) Regulated: Transmission $ 223.2 4.1% $ 242.7 4.0% Distribution 1,289.8 4.5% 1,197.5 4.9% General 13.2 8.5% 13.7 7.1% Non-depreciable 60.4 N/A 64.7 N/A Total regulated 1,586.6 1,518.6 Unregulated: Production / Generation — N/A 0.2 N/A Other 21.2 6.7% 21.1 7.0% Non-depreciable 7.8 N/A 4.2 N/A Total unregulated 29.0 25.5 Total property, plant and equipment in service $ 1,615.6 4.3% $ 1,544.1 5.0% (a) Composite rates for 2017 include property classified in non-current assets of discontinued operations and held-for-sale businesses. |
Changes in the Liability for Generation AROs | Changes in the Liability for AROs $ in millions Balance at December 31, 2016 $ 15.0 Calendar 2017 Revisions to cash flow and timing estimates (0.1 ) Accretion expense 0.4 Settlements (0.2 ) Balance at December 31, 2017 15.1 Calendar 2018 Revisions to cash flow and timing estimates (2.6 ) Accretion expense 0.3 Settlements (a) (3.4 ) Balance at December 31, 2018 $ 9.4 (a) Primarily includes settlement related to transfer of Beckjord Facility. See Note 16 – Dispositions for additional information. |
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, 2016 $ 126.5 Calendar 2017 Additions 12.0 Settlements (5.7 ) Balance at December 31, 2017 132.8 Calendar 2018 Additions 14.3 Settlements (8.0 ) Balance at December 31, 2018 $ 139.1 |
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, 2018 and 2017 : December 31, 2018 December 31, 2017 $ in millions Composite Rate Composite Rate (a) Regulated: Transmission $ 386.7 2.4% $ 414.6 2.4% Distribution 1,796.4 3.2% 1,735.9 3.4% General 30.9 3.6% 31.2 3.1% Non-depreciable 60.4 N/A 64.6 N/A Total regulated 2,274.4 2,246.3 Unregulated: Other — N/A 0.2 2.7% Non-depreciable — N/A 0.7 N/A Total unregulated — 0.9 Total property, plant and equipment in service $ 2,274.4 3.0% $ 2,247.2 3.4% |
Changes in the Liability for Generation AROs | Changes in the Liability for Generation AROs $ in millions Balance at December 31, 2016 $ 8.2 Calendar 2017 Accretion expense 0.1 Settlements (0.3 ) Balance at December 31, 2017 8.0 Calendar 2018 Settlements (a) (3.3 ) Balance at December 31, 2018 $ 4.7 (a) Primarily includes settlement related to transfer of Beckjord Facility. See Note 15 – Dispositions for additional information. |
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, 2016 $ 126.5 Calendar 2017 Additions 12.0 Settlements (5.7 ) Balance at December 31, 2017 132.8 Calendar 2018 Additions 14.3 Settlements (8.0 ) Balance at December 31, 2018 $ 139.1 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
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, 2018 and 2017 . See Note 6 – Derivative Instruments and Hedging Activities for the fair values of our derivative instruments. December 31, 2018 December 31, 2017 $ in millions Cost Fair Value Cost Fair Value Assets Money market funds $ 0.4 $ 0.4 $ 0.3 $ 0.3 Equity securities 2.4 3.5 2.5 4.2 Debt securities 4.1 4.0 4.3 4.3 Hedge funds 0.1 0.1 0.1 0.2 Tangible assets 0.1 0.1 0.1 0.1 Total assets $ 7.1 $ 8.1 $ 7.3 $ 9.1 Carrying Value Fair Value Carrying Value Fair Value Liabilities Long-term debt $ 1,475.9 $ 1,519.6 $ 1,704.8 $ 1,819.3 |
Fair Value of Assets and Liabilities Measured on Recurring Basis | The fair value of assets and liabilities at December 31, 2018 and 2017 and the respective category within the fair value hierarchy for DPL was determined as follows: $ in millions Fair Value at December 31, 2018 (a) Fair Value at December 31, 2017 (a) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets Master trust assets Money market funds $ 0.4 $ — $ — $ 0.4 $ 0.3 $ — $ — $ 0.3 Equity securities — 3.5 — 3.5 — 4.2 — 4.2 Debt securities — 4.0 — 4.0 — 4.3 — 4.3 Hedge funds — 0.1 — 0.1 — 0.2 — 0.2 Tangible assets — 0.1 — 0.1 — 0.1 — 0.1 Total Master trust assets 0.4 7.7 — 8.1 0.3 8.8 — 9.1 Derivative assets Interest rate hedge — 1.5 — 1.5 — 1.5 — 1.5 Total Derivative assets — 1.5 — 1.5 — 1.5 — 1.5 Total assets $ 0.4 $ 9.2 $ — $ 9.6 $ 0.3 $ 10.3 $ — $ 10.6 Liabilities Long-term debt $ — $ 1,501.9 $ 17.7 $ 1,519.6 $ — $ 1,801.5 $ 17.8 $ 1,819.3 Total liabilities $ — $ 1,501.9 $ 17.7 $ 1,519.6 $ — $ 1,801.5 $ 17.8 $ 1,819.3 (a) Includes credit valuation adjustment |
Fair Value Measurements, Nonrecurring | The following table summarizes major categories of assets 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 (b) Level 1 Level 2 Level 3 Loss Long-lived assets (a) Year ended December 31, 2016 Conesville December 31, 2016 $ 25.0 $ — $ — $ 1.1 23.9 (a) See Note 17 – Fixed-asset Impairments for further information (b) Carrying amount at date of valuation |
Fair Value Measurement Inputs and Valuation Techniques [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 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 |
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, 2018 and 2017 . See also Note 6 – Derivative Instruments and Hedging Activities for the fair values of our derivative instruments. December 31, 2018 December 31, 2017 $ in millions Cost Fair Value Cost Fair Value Assets Money market funds $ 0.4 $ 0.4 $ 0.3 $ 0.3 Equity securities 2.4 3.5 2.5 4.2 Debt securities 4.1 4.0 4.3 4.3 Hedge funds 0.1 0.1 0.1 0.2 Tangible assets 0.1 0.1 0.1 0.1 Total assets $ 7.1 $ 8.1 $ 7.3 $ 9.1 Carrying Value Fair Value Carrying Value Fair Value Liabilities Long-term debt $ 586.1 $ 593.8 $ 646.6 $ 658.4 |
Fair Value of Assets and Liabilities Measured on Recurring Basis | The fair value of assets and liabilities at December 31, 2018 and 2017 and the respective category within the fair value hierarchy for DP&L was determined as follows: $ in millions Fair Value at December 31, 2018 (a) Fair Value at December 31, 2017 (a) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets Master trust assets Money market funds $ 0.4 $ — $ — $ 0.4 $ 0.3 $ — $ — $ 0.3 Equity securities — 3.5 — 3.5 — 4.2 — 4.2 Debt securities — 4.0 — 4.0 — 4.3 — 4.3 Hedge funds — 0.1 — 0.1 — 0.2 — 0.2 Tangible assets — 0.1 — 0.1 — 0.1 — 0.1 Total Master trust assets 0.4 7.7 — 8.1 0.3 8.8 — 9.1 Derivative assets Interest rate hedges — 1.5 — 1.5 — 1.5 — 1.5 Total derivative assets — 1.5 — 1.5 — 1.5 — 1.5 Total assets $ 0.4 $ 9.2 $ — $ 9.6 $ 0.3 $ 10.3 $ — $ 10.6 Liabilities Long-term debt $ — $ 576.1 $ 17.7 $ 593.8 $ — $ 640.6 $ 17.8 658.4 Total liabilities $ — $ 576.1 $ 17.7 $ 593.8 $ — $ 640.6 $ 17.8 $ 658.4 (a) Includes credit valuation adjustment |
Derivative Instruments and He_2
Derivative Instruments and Hedging Activities (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Schedule of Notional Amounts of Outstanding Derivative Positions | At December 31, 2018 , DPL's outstanding derivative instruments were as follows: Commodity Accounting Treatment (a) Unit Purchases Sales Net Purchases/ (Sales) Interest Rate Swaps Designated USD $ 140,000.0 $ — $ 140,000.0 (a) Refers to whether the derivative instruments have been designated as a cash flow hedge. At December 31, 2017 , DPL's outstanding derivative instruments were as follows: Commodity Accounting Treatment (a) Unit Purchases Sales Net Purchases/ (Sales) FTRs (b) Not designated MWh 2.1 — 2.1 Natural Gas (b) Not designated Dths 3,322.5 (390.0 ) 2,932.5 Forward Power Contracts (b) Designated MWh 678.5 (1,667.0 ) (988.5 ) Forward Power Contracts (b) 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. (b) As of December 31, 2017, the related asset and liability balances for these derivative instruments were classified in assets and liabilities of discontinued operations and held-for-sale businesses. |
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, 2018 2017 2016 $ in millions (net of tax) Power Interest Rate Power Interest Rate Power Interest Rate Beginning accumulated derivative gain / (loss) in AOCI $ (2.8 ) $ 17.5 $ (4.3 ) $ 17.4 $ 9.2 $ 17.5 Net gains / (losses) associated with current period hedging transactions — (0.1 ) 8.8 0.8 15.7 0.4 Net gains / (losses) reclassified to earnings: Interest Expense — (0.8 ) — (0.7 ) — (0.5 ) Income / (loss) from discontinued operations before income tax 3.2 — (7.3 ) — (29.2 ) — Ending accumulated derivative gain / (loss) in AOCI $ 0.4 $ 16.6 $ (2.8 ) $ 17.5 $ (4.3 ) $ 17.4 Portion expected to be reclassified to earnings in the next twelve months (a) $ — $ (0.8 ) Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) 0 20 (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, 2018 , 2017 and 2016 : Year ended December 31, 2018 $ in millions FTRs Power Natural Gas Total Change in unrealized gain / (loss) $ 0.3 $ — $ (0.1 ) $ 0.2 Realized gain / (loss) 0.4 — 0.3 0.7 Total $ 0.7 $ — $ 0.2 $ 0.9 Recorded in Statement of Operations: gain / (loss) Income / (loss) from discontinued operations before income tax $ 0.7 $ — $ 0.2 $ 0.9 Total $ 0.7 $ — $ 0.2 $ 0.9 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 in Statement of Operations: gain / (loss) Income / (loss) from discontinued operations before income tax $ 0.4 $ 1.2 $ 1.6 $ 3.2 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 in Statement of Operations: gain / (loss) Income / (loss) from discontinued operations before income tax $ (0.3 ) $ (3.2 ) $ 2.6 $ (0.9 ) Total $ (0.3 ) $ (3.2 ) $ 2.6 $ (0.9 ) |
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, 2018 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 prepayments and current assets) Interest Rate Swaps Designated $ 0.9 $ — $ — $ 0.9 Long-term derivative positions (presented in Other deferred assets) Interest Rate Swaps Designated 0.6 — — 0.6 Total assets $ 1.5 $ — $ — $ 1.5 (a) Includes credit valuation adjustment. 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 Current assets of discontinued operations and held-for-sale businesses) Forward power contracts Designated $ 4.9 $ (4.9 ) $ — $ — Forward power contracts Not designated 5.3 (3.7 ) — 1.6 FTRs Not designated 0.2 (0.1 ) — 0.1 Long-term derivative positions (presented in Other deferred assets) Interest rate swaps Designated 1.5 — — 1.5 Long-term derivative positions (presented in Non-current assets of discontinued operations and held-for-sale businesses) Forward power contracts Not designated 0.6 — — 0.6 Total assets $ 12.5 $ (8.7 ) $ — $ 3.8 Liabilities Short-term derivative positions (presented in Current liabilities of discontinued operations and held-for-sale businesses) 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. |
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 2018 2017 Interest rate hedges in a Current asset position Cash Flow Hedge Other prepayments and current assets Gross Fair Value as presented in the Balance Sheets $ 0.9 $ — Interest rate hedges in a non-current asset position Cash Flow Hedge Other deferred assets Gross Fair Value as presented in the Balance Sheets $ 0.6 $ 1.5 |
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, 2018 2017 2016 $ in millions (net of tax) Interest Rate Power Interest Rate Power Interest Rate Beginning accumulated derivative gain / (loss) in AOCI $ 1.4 $ (4.3 ) $ 1.6 $ 9.2 $ 2.0 Net gains / (losses) associated with current period hedging transactions (0.1 ) 11.9 0.5 15.7 0.4 Net gains / (losses) reclassified to earnings: Interest expense (0.7 ) — (0.7 ) — (0.8 ) Loss from discontinued operations — (5.5 ) — (29.2 ) — Transfer of generation assets to subsidiary of parent — (2.1 ) — — — Ending accumulated derivative gain / (loss) in AOCI $ 0.6 $ — $ 1.4 $ (4.3 ) $ 1.6 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) 20 |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Debt Instrument [Line Items] | |
Long-term Debt | Long-term debt $ in millions Interest Rate Maturity December 31, 2018 December 31, 2017 Term loan - rates from: 3.57% - 4.82% (a) and 4.00% - 4.60% (b) 2022 $ 436.1 $ 440.6 Tax-exempt First Mortgage Bonds - rates from: 2.49% - 2.93% (a) and 1.29% - 1.42% (b) 2020 140.0 200.0 U.S. Government note 4.2% 2061 17.7 17.8 Unamortized deferred financing costs (6.3 ) (9.8 ) Unamortized debt discounts and premiums, net (1.4 ) (2.0 ) Total long-term debt at subsidiary 586.1 646.6 Bank term loan - rates from: 3.02% - 4.10% (a) and 2.67% - 3.02% (b) 2020 — 70.0 Senior unsecured bonds 6.75% 2019 99.0 200.0 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 (4.3 ) (6.8 ) Unamortized debt discounts and premiums, net (0.5 ) (0.6 ) Total long-term debt 1,475.9 1,704.8 Less: current portion (103.6 ) (4.6 ) Long-term debt, net of current portion $ 1,372.3 $ 1,700.2 (a) Range of interest rates for the year ended December 31, 2018 . (b) Range of interest rates for the year ended December 31, 2017 . (c) Note payable to related party. See Note 12 – Related Party Transactions for additional information. |
Long-term Debt Maturities | At December 31, 2018 , maturities of long-term debt are summarized as follows: Due during the years ending December 31, $ in millions 2019 $ 103.6 2020 144.7 2021 784.7 2022 422.8 2023 0.2 Thereafter 32.4 1,488.4 Unamortized discounts and premiums, net (1.9 ) Deferred financing costs, net (10.6 ) Total long-term debt $ 1,475.9 |
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, 2018 December 31, 2017 Term loan - rates from: 3.57% - 4.82% (a) and 4.00% - 4.60% (b) 2022 $ 436.1 $ 440.6 Tax-exempt First Mortgage Bonds - rates from: 2.49% - 2.93% (a) and 1.29% - 1.42% (b) 2020 140.0 200.0 U.S. Government note 4.2% 2061 17.7 17.8 Unamortized deferred financing costs (6.3 ) (9.8 ) Unamortized debt discount (1.4 ) (2.0 ) Total long-term debt 586.1 646.6 Less: current portion (4.6 ) (4.6 ) Long-term debt, net of current portion $ 581.5 $ 642.0 (a) Range of interest rates for the year ended December 31, 2018 . (b) Range of interest rates for the year ended December 31, 2017 |
Long-term Debt Maturities | At December 31, 2018 , maturities of long-term debt are summarized as follows: Due during the years ending December 31, $ in millions 2019 $ 4.6 2020 144.7 2021 4.7 2022 422.8 2023 0.2 Thereafter 16.8 593.8 Unamortized discounts and premiums, net (1.4 ) Deferred financing costs, net (6.3 ) Total long-term debt $ 586.1 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
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 2018 2017 2016 Computation of tax expense / (benefit) Federal income tax expense / (benefit)(a) $ 6.7 $ (2.3 ) $ 4.3 Increases (decreases) in tax resulting from: State income taxes, net of federal effect 0.1 0.1 — Depreciation of flow-through differences (4.6 ) 1.1 3.3 Investment tax credit amortized (0.3 ) (0.3 ) (0.4 ) Deferred tax adjustments — (0.7 ) (9.3 ) Accrual (settlement) for open tax years — (0.4 ) 2.0 Other, net (b) (1.2 ) (2.5 ) (2.3 ) Tax expense / (benefit) $ 0.7 $ (5.0 ) $ (2.4 ) Components of tax expense / (benefit) Federal - current $ (17.9 ) $ 23.8 $ (3.3 ) State and Local - current 0.5 0.2 — Total current (17.4 ) 24.0 (3.3 ) Federal - deferred 18.3 (28.8 ) 0.8 State and local - deferred (0.2 ) (0.2 ) 0.1 Total deferred 18.1 (29.0 ) 0.9 Tax expense / (benefit) $ 0.7 $ (5.0 ) $ (2.4 ) (a) The statutory tax rate of 21% in 2018 and 35% in 2017 and 2016 was applied to pre-tax earnings. (b) Includes expense / (benefit) of $3.5 million and $(0.9) million in the years ended December 31, 2017 and 2016 , respectively, of income tax related to adjustments from prior years. The 2018 and 2017 tax years also include a remeasurement of deferred tax expense related to the recent enactment of the TCJA of a benefit of $(1.2) million and $(0.4) million , respectively. |
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, 2018 , 2017 and 2016 : Years ended December 31, 2018 2017 2016 Statutory Federal tax rate 21.0 % 35.0 % 35.0 % State taxes, net of Federal tax benefit 0.4 % (1.5 )% 0.2 % AFUDC - equity (0.1 )% 4.9 % (5.0 )% Depreciation of flow-through differences (14.6 )% (17.6 )% 26.7 % Amortization of investment tax credits (1.0 )% 5.1 % (3.3 )% Deferred tax adjustments — % 11.0 % (75.1 )% Permanent differences — % 4.8 % 2.8 % Other, net (3.5 )% 35.2 % (0.7 )% Effective tax rate 2.2 % 76.9 % (19.4 )% |
Components of Deferred Tax Assets and Liabilities | Components of Deferred Tax Assets and Liabilities December 31, $ in millions 2018 2017 Net non-current assets / (liabilities) Depreciation / property basis $ (112.0 ) $ (113.4 ) Income taxes recoverable 25.0 11.0 Regulatory assets (15.4 ) (23.1 ) Investment tax credit 0.5 0.7 Compensation and employee benefits 1.4 19.0 Intangibles (0.3 ) (0.4 ) Long-term debt (2.1 ) (0.2 ) Other (a) (13.2 ) (7.1 ) Net non-current liabilities $ (116.1 ) $ (113.5 ) (a) The Other caption includes deferred tax assets of $10.9 million in 2018 and $9.3 million in 2017 related to state and local tax net operating loss carryforwards, net of related valuation allowances of $10.9 million in 2018 and $9.3 million in 2017 . These net operating loss carryforwards expire from 2019 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 2018 2017 2016 Tax expense / (benefit) $ 0.2 $ 0.2 $ (9.6 ) |
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, 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 Calendar 2018 Tax positions taken during prior period — Lapse of Statute of Limitations — Balance at December 31, 2018 $ 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 2018 2017 2016 Computation of tax expense Federal income tax expense (a) $ 22.2 $ 31.0 $ 50.1 Increases (decreases) in tax resulting from: State income taxes, net of federal effect 0.6 0.4 0.4 Depreciation of flow-through differences (4.3 ) 1.2 3.0 Investment tax credit amortized (0.3 ) (0.3 ) (0.4 ) Accrual (settlement) for open tax years — (0.5 ) 3.4 Other, net (b) (0.5 ) (0.7 ) (10.5 ) Total tax expense $ 17.7 $ 31.1 $ 46.0 Components of tax expense Federal - current $ 1.4 $ 13.5 $ 37.7 State and Local - current — 0.2 0.5 Total current 1.4 13.7 38.2 Federal - deferred 15.5 17.0 7.7 State and local - deferred 0.8 0.4 0.1 Total deferred 16.3 17.4 7.8 Total tax expense $ 17.7 $ 31.1 $ 46.0 (a) The statutory tax rate of 21% in 2018 and 35% in 2017 and 2016 was applied to pre-tax earnings. (b) Includes expense / (benefit) of $(0.7) million and $(0.4) million in the years ended December 31, 2017 and 2016 , 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, 2018 , 2017 and 2016 : Years ended December 31, 2018 2017 2016 Statutory Federal tax rate 21.0 % 35.0 % 35.0 % State taxes, net of Federal tax benefit 0.6 % 0.4 % 0.3 % AFUDC - Equity (0.1 )% 1.4 % 2.1 % Amortization of investment tax credits (0.3 )% (0.4 )% (0.3 )% Depreciation of flow-through differences (4.0 )% — % — % Other - net (0.2 )% (1.3 )% (5.1 )% Effective tax rate 17.0 % 35.1 % 32.0 % |
Components of Deferred Tax Assets and Liabilities | Components of Deferred Tax Assets and Liabilities December 31, $ in millions 2018 2017 Net non-current assets / (liabilities) Depreciation / property basis $ (130.6 ) $ (126.5 ) Income taxes recoverable 25.0 11.0 Regulatory assets (16.2 ) (23.9 ) Investment tax credit 0.5 0.4 Compensation and employee benefits 0.3 17.6 Other (10.7 ) (9.6 ) Net non-current liabilities $ (131.7 ) $ (131.0 ) |
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 2018 2017 2016 Tax expense / (benefit) $ (0.3 ) $ 4.0 $ (7.0 ) |
Reconciliation of Unrecognized Tax Benefits | A reconciliation of the beginning and ending amount of unrecognized tax benefits for DP&L is as follows: $ in millions Balance at December 31, 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 Calendar 2018 Tax positions taken during prior period — Lapse of Statute of Limitations — Balance at December 31, 2018 $ 4.8 |
Benefit Plans (Tables)
Benefit Plans (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
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, 2018 and 2017 . 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 $1.8 million and $1.1 million of costs billed to the Service Company for the years ended December 31, 2018 and 2017 . $ in millions Years ended December 31, Change in benefit obligation 2018 2017 Benefit obligation at January 1 $ 436.9 $ 419.6 Service cost 6.1 5.7 Interest cost 13.8 14.2 Plan amendments 5.1 — Plan curtailment — 3.0 Actuarial (gain) / loss (34.6 ) 28.1 Benefits paid (40.8 ) (33.7 ) Benefit obligation at December 31 386.5 436.9 Change in plan assets Fair value of plan assets at January 1 357.5 341.0 Actual return on plan assets (11.7 ) 44.8 Employer contributions 7.9 5.4 Benefits paid (40.8 ) (33.7 ) Fair value of plan assets at December 31 312.9 357.5 Unfunded status of plan $ (73.6 ) $ (79.4 ) December 31, Amounts recognized in the Balance sheets 2018 2017 Current liabilities $ (0.4 ) $ (0.4 ) Non-current liabilities (73.2 ) (79.0 ) Net liability at end of year $ (73.6 ) $ (79.4 ) Amounts recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax Components: Prior service cost $ 9.1 $ 4.9 Net actuarial loss 103.3 111.4 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 112.4 $ 116.3 Recorded as: Regulatory asset $ 87.2 $ 92.1 Accumulated other comprehensive income 25.2 24.2 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 112.4 $ 116.3 |
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, 2018 and 2017 . 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 $1.8 million and $1.1 million of costs billed to the Service Company for the years ended December 31, 2018 and 2017 . $ in millions Years ended December 31, Change in benefit obligation 2018 2017 Benefit obligation at January 1 $ 436.9 $ 419.6 Service cost 6.1 5.7 Interest cost 13.8 14.2 Plan amendments 5.1 — Plan curtailment — 3.0 Actuarial (gain) / loss (34.6 ) 28.1 Benefits paid (40.8 ) (33.7 ) Benefit obligation at December 31 386.5 436.9 Change in plan assets Fair value of plan assets at January 1 357.5 341.0 Actual return on plan assets (11.7 ) 44.8 Employer contributions 7.9 5.4 Benefits paid (40.8 ) (33.7 ) Fair value of plan assets at December 31 312.9 357.5 Unfunded status of plan $ (73.6 ) $ (79.4 ) December 31, Amounts recognized in the Balance sheets 2018 2017 Current liabilities $ (0.4 ) $ (0.4 ) Non-current liabilities (73.2 ) (79.0 ) Net liability at end of year $ (73.6 ) $ (79.4 ) Amounts recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax Components: Prior service cost $ 9.1 $ 4.9 Net actuarial loss 103.3 111.4 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 112.4 $ 116.3 Recorded as: Regulatory asset $ 87.2 $ 92.1 Accumulated other comprehensive income 25.2 24.2 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 112.4 $ 116.3 |
Schedule of Net Periodic Benefit Cost / (Income) | The net periodic benefit cost of the pension plans was: Years ended December 31, $ in millions 2018 2017 2016 Service cost $ 6.1 $ 5.7 $ 5.7 Interest cost 13.8 14.2 14.7 Expected return on assets (21.2 ) (22.8 ) (22.8 ) Plan curtailment (a) — 4.1 3.8 Amortization of unrecognized: Actuarial loss 6.4 5.3 4.3 Prior service cost 0.9 1.1 1.8 Net periodic benefit cost $ 6.0 $ 7.6 $ 7.5 Rates relevant to each year's expense calculations Discount rate 3.66 % 4.28 % 4.49 % Expected return on plan assets 6.25 % 6.50 % 6.50 % (a) As a result of the decision to retire certain coal-fired plants, we recognized a plan curtailment of $4.1 million and $3.8 million in 2017 and 2016, respectively. |
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 2018 2017 2016 Net actuarial loss $ 3.4 $ 9.1 $ 20.9 Plan curtailment (a) — (4.1 ) (3.8 ) Reversal of amortization item: Net actuarial loss (6.4 ) (5.3 ) (4.3 ) Prior service cost (0.9 ) (1.1 ) (1.8 ) Total recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities $ (3.9 ) $ (1.4 ) $ 11.0 Total recognized in net periodic benefit cost and Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities $ 2.1 $ 6.2 $ 18.5 (a) As a result of the decision to retire certain coal-fired plants, we recognized a plan curtailment of $4.1 million and $3.8 million in 2017 and 2016, respectively. |
Weighted Average Assumptions Used to Determine Benefit Obligations | The weighted average assumptions used to determine benefit obligations at December 31, 2018 , 2017 and 2016 were: Benefit Obligation Assumptions Pension 2018 2017 2016 Discount rate for obligations 4.35% 3.66% 4.28% 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 2018 : Long-Term Percentage of plan assets as of December 31, Asset category 2018 2017 Equity Securities 38% 33% 35% Debt Securities 56% 58% 55% Cash and Cash Equivalents —% 1% —% Real Estate 6% 8% 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 2019 $ 26.7 2020 $ 26.5 2021 $ 26.3 2022 $ 26.0 2023 $ 25.9 2024 - 2028 $ 125.1 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Schedule of Amounts Recognized in Balance Sheet | December 31, 2018 and 2017 . 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 $1.8 million and $1.1 million of costs billed to the Service Company for the years ended December 31, 2018 and 2017 or $3.3 million and $0.7 million of costs billed to AES Ohio Generation for the years ended December 31, 2018 and 2017 . $ in millions Years ended December 31, Change in benefit obligation 2018 2017 Benefit obligation at January 1 $ 436.9 $ 419.6 Service cost 6.1 5.7 Interest cost 13.8 14.2 Plan amendments 5.1 — Plan curtailment — 3.0 Actuarial (gain) / loss (34.6 ) 28.1 Benefits paid (40.8 ) (33.7 ) Benefit obligation at December 31 386.5 436.9 Change in plan assets Fair value of plan assets at January 1 357.5 341.0 Actual return on plan assets (11.7 ) 44.8 Employer contributions 7.9 5.4 Benefits paid (40.8 ) (33.7 ) Fair value of plan assets at December 31 312.9 357.5 Unfunded status of plan $ (73.6 ) $ (79.4 ) December 31, Amounts recognized in the Balance sheets 2018 2017 Current liabilities $ (0.4 ) $ (0.4 ) Non-current liabilities (73.2 ) (79.0 ) Net liability at end of year $ (73.6 ) $ (79.4 ) Amounts recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax Components: Prior service cost $ 10.4 $ 6.7 Net actuarial loss 137.2 148.3 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 147.6 $ 155.0 Recorded as: Regulatory asset $ 87.3 $ 92.2 Accumulated other comprehensive income 60.3 62.8 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 147.6 $ 155.0 |
Schedule of Net Periodic Benefit Cost / (Income) | The net periodic benefit cost of the pension plans was: Years ended December 31, $ in millions 2018 2017 2016 Service cost $ 6.1 $ 5.7 $ 5.7 Interest cost 13.8 14.2 14.7 Expected return on assets (21.2 ) (22.8 ) (22.8 ) Plan curtailment (a) — 5.6 5.7 Amortization of unrecognized: Actuarial loss 9.4 8.7 7.2 Prior service cost 1.4 1.5 3.0 Net periodic benefit cost $ 9.5 $ 12.9 $ 13.5 Rates relevant to each year's expense calculations Discount rate 3.66 % 4.28 % 4.49 % Expected return on plan assets 6.25 % 6.50 % 6.50 % (a) As a result of the decision to retire certain coal-fired plants, we recognized a plan curtailment of $5.6 million and $5.7 million in 2017 and 2016, respectively. |
Weighted Average Assumptions Used to Determine Benefit Obligations | The weighted average assumptions used to determine benefit obligations at December 31, 2018 , 2017 and 2016 were: Benefit Obligation Assumptions Pension 2018 2017 2016 Discount rate for obligations 4.35% 3.66% 4.28% 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 2018 : Long-Term Percentage of plan assets as of December 31, Asset category 2018 2017 Equity Securities 38% 33% 35% Debt Securities 56% 58% 55% Cash and Cash Equivalents —% 1% —% Real Estate 6% 8% 10% |
Fair Value Measurements for Plan Assets | The fair values of our pension plan assets at December 31, 2018 by asset category are as follows: Fair Value Measurements for Pension Plan Assets at December 31, 2018 $ in millions Market Value at December 31, 2018 Quoted prices Significant Significant Asset category (Level 1) (Level 2) (Level 3) Mutual funds: U.S. equities (a) $ 79.3 $ 79.3 $ — $ — International equities (a) 25.9 25.9 — — Fixed income (b) 143.7 143.7 — — Fixed income securities: U.S. Treasury securities 37.5 37.5 — — Cash and cash equivalents: Money market funds (c) 2.4 2.4 — — Other investments: Core property collective fund (d) 24.1 — 24.1 — Total pension plan assets $ 312.9 $ 288.8 $ 24.1 $ — (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 is comprised of investments in U.S. treasury obligations that seek to preserve principal and maintain liquidity while providing current income. The funds are valued at the assets’ amortized cost to maintain a stable per share net asset value. (d) 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, 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: (c) Core property collective fund 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. |
Estimated Future Benefit Payments and Medicare Part D Reimbursements | Estimated future benefit payments $ in millions due within the following years: Pension 2019 $ 26.7 2020 $ 26.5 2021 $ 26.3 2022 $ 26.0 2023 $ 25.9 2024 - 2028 $ 125.1 |
Pension [Member] | |
Fair Value Measurements for Plan Assets | The fair values of our pension plan assets at December 31, 2018 by asset category are as follows: Fair Value Measurements for Pension Plan Assets at December 31, 2018 $ in millions Market Value at December 31, 2018 Quoted prices Significant Significant Asset category (Level 1) (Level 2) (Level 3) Mutual funds: U.S. equities (a) $ 79.3 $ 79.3 $ — $ — International equities (a) 25.9 25.9 — — Fixed income (b) 143.7 143.7 — — Fixed income securities: U.S. Treasury securities 37.5 37.5 — — Cash and cash equivalents: Money market funds (c) 2.4 2.4 — — Other investments: Core property collective fund (d) 24.1 — 24.1 — Total pension plan assets $ 312.9 $ 288.8 $ 24.1 $ — (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 is comprised of investments in U.S. treasury obligations that seek to preserve principal and maintain liquidity while providing current income. The funds are valued at the assets’ amortized cost to maintain a stable per share net asset value. (d) 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, 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: (c) Core property collective fund 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. |
Pension [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Pension And Postretirement Benefit Plans' Obligations And Assets | The following tables set forth the changes in our pension plan's obligations and assets recorded on the Balance Sheets at December 31, 2018 and 2017 . 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 $1.8 million and $1.1 million of costs billed to the Service Company for the years ended December 31, 2018 and 2017 or $3.3 million and $0.7 million of costs billed to AES Ohio Generation for the years ended December 31, 2018 and 2017 . $ in millions Years ended December 31, Change in benefit obligation 2018 2017 Benefit obligation at January 1 $ 436.9 $ 419.6 Service cost 6.1 5.7 Interest cost 13.8 14.2 Plan amendments 5.1 — Plan curtailment — 3.0 Actuarial (gain) / loss (34.6 ) 28.1 Benefits paid (40.8 ) (33.7 ) Benefit obligation at December 31 386.5 436.9 Change in plan assets Fair value of plan assets at January 1 357.5 341.0 Actual return on plan assets (11.7 ) 44.8 Employer contributions 7.9 5.4 Benefits paid (40.8 ) (33.7 ) Fair value of plan assets at December 31 312.9 357.5 Unfunded status of plan $ (73.6 ) $ (79.4 ) December 31, Amounts recognized in the Balance sheets 2018 2017 Current liabilities $ (0.4 ) $ (0.4 ) Non-current liabilities (73.2 ) (79.0 ) Net liability at end of year $ (73.6 ) $ (79.4 ) Amounts recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax Components: Prior service cost $ 10.4 $ 6.7 Net actuarial loss 137.2 148.3 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 147.6 $ 155.0 Recorded as: Regulatory asset $ 87.3 $ 92.2 Accumulated other comprehensive income 60.3 62.8 Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $ 147.6 $ 155.0 |
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 2018 2017 2016 Net actuarial loss $ 3.4 $ 9.1 $ 20.9 Plan curtailment (a) — (5.6 ) (5.7 ) Reversal of amortization item: Net actuarial loss (9.4 ) (8.7 ) (7.2 ) Prior service cost (1.4 ) (1.5 ) (3.0 ) Total recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities $ (7.4 ) $ (6.7 ) $ 5.0 Total recognized in net periodic benefit cost and Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities $ 2.1 $ 6.2 $ 18.5 (a) As a result of the decision to retire certain coal-fired plants, we recognized a plan curtailment of $5.6 million and $5.7 million in 2017 and 2016, respectively. |
Contractual Obligations, Comm_2
Contractual Obligations, Commercial Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
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, 2018 , these include: Payments due in: $ in millions Total Less than 2 - 3 4 - 5 More than Electricity purchase commitments $ 209.4 $ 139.5 $ 69.9 $ — $ — Purchase orders and other contractual obligations $ 40.2 $ 11.4 $ 14.8 $ 14.0 $ — |
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, 2018 , these include: Payments due in: $ in millions Total Less than 2 - 3 4 - 5 More than Electricity purchase commitments $ 209.4 $ 139.5 $ 69.9 $ — $ — Purchase orders and other contractual obligations $ 39.8 $ 11.3 $ 14.7 $ 13.8 $ — |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Entity Information [Line Items] | |
Schedule of Related Party Transactions | The following table provides a summary of our related party transactions: Years ended December 31, $ in millions 2018 2017 2016 Transactions with the Service Company Charges for services provided $ 41.0 $ 46.5 $ 42.8 Charges to the Service Company $ 4.9 $ 4.2 $ 4.6 Transactions with other AES affiliates: Payments for health, welfare and benefit plans $ 7.9 $ 15.4 $ 9.6 Consulting services $ 2.0 $ — $ — Balances with related parties: At December 31, 2018 At December 31, 2017 Net payable to the Service Company $ (4.8 ) $ (3.9 ) Net payable to other AES affiliates $ (0.5 ) $ (0.6 ) |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Entity Information [Line Items] | |
Schedule of Related Party Transactions | The following table provides a summary of our related party transactions: Years ended December 31, $ in millions 2018 2017 2016 DP&L Cost of revenues: Fuel and power purchased from AES Ohio Generation $ — $ 5.4 $ 8.7 DP&L Operation & Maintenance Expenses: Premiums charged for insurance services provided by MVIC (a) $ 2.7 $ 3.1 $ 3.4 Transactions with the Service Company: Charges for services provided $ 25.7 $ 39.0 $ 38.7 Charges to the Service Company $ 4.9 $ 4.2 $ 4.5 Transactions with other AES affiliates: Charges for health, welfare and benefit plans $ 8.7 $ 14.3 $ 9.4 Charges to affiliates for non-power goods or services (b) $ 7.1 $ 3.7 $ 5.7 Consulting services $ 2.0 $ — $ — Balances with related parties: At December 31, 2018 At December 31, 2017 Net payable to the Service Company $ (4.8 ) $ (3.9 ) Net receivable from / (payable) to other AES affiliates $ (0.5 ) $ 4.8 (a) 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 . (b) In the normal course of business DP&L incurred and recorded expenses on behalf of DPL affiliates. 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, 2018 | |
Segment Reporting Information [Line Items] | |
Schedule of Segment Reporting Information, by Segment [Table Text Block] | The following tables present financial information for DPL’s reportable business segment: $ in millions Utility Other (a) Adjustments and Eliminations DPL Consolidated Year ended December 31, 2018 Revenues from external customers $ 737.8 $ 38.1 $ — $ 775.9 Intersegment revenues 0.9 2.9 (3.8 ) — Total revenues $ 738.7 $ 41.0 $ (3.8 ) $ 775.9 Depreciation and amortization $ 74.5 $ (1.4 ) $ — $ 73.1 Fixed-asset impairment $ — $ 2.8 $ — $ 2.8 Interest expense $ 27.3 $ 70.7 $ — $ 98.0 Income / (loss) from continuing operations before income tax $ 104.4 $ (72.5 ) $ — $ 31.9 Cash capital expenditures $ 93.1 $ 10.5 $ — $ 103.6 Total assets (end of year) $ 1,819.6 $ 545.9 $ (482.4 ) $ 1,883.1 $ in millions Utility Other (a) Adjustments and Eliminations DPL Consolidated Year ended December 31, 2017 Revenues from external customers $ 718.9 $ 25.0 $ — $ 743.9 Intersegment revenues 1.1 4.4 (5.5 ) — Total revenues $ 720.0 $ 29.4 $ (5.5 ) $ 743.9 Depreciation and amortization $ 75.3 $ 0.8 $ — $ 76.1 Interest expense $ 30.5 $ 79.5 $ — $ 110.0 Income / (loss) from continuing operations before income tax $ 88.5 $ (95.0 ) $ — $ (6.5 ) Cash capital expenditures $ 85.6 $ 35.9 $ — $ 121.5 Total assets (end of year) $ 1,695.9 $ 736.5 $ (383.2 ) $ 2,049.2 $ in millions Utility Other (a) Adjustments and Eliminations DPL Consolidated Year ended December 31, 2016 Revenues from external customers $ 806.7 $ 27.5 $ — $ 834.2 Intersegment revenues 1.3 5.7 (7.0 ) — Total revenues $ 808.0 $ 33.2 $ (7.0 ) $ 834.2 Depreciation and amortization $ 71.0 $ 2.6 $ — $ 73.6 Fixed-asset impairment $ — $ 23.9 $ — $ 23.9 Interest expense $ 25.4 $ 82.3 $ (0.3 ) $ 107.4 Income / (loss) from continuing operations before income tax $ 143.0 $ (130.6 ) $ — $ 12.4 Cash capital expenditures $ 83.4 $ 65.1 $ — $ 148.5 Total assets (end of year) $ 1,710.5 $ 1,145.9 $ (437.2 ) $ 2,419.2 (a) "Other" includes Cash capital expenditures and Total assets related to the assets of discontinued operations and held-for-sale businesses for all periods presented. |
Revenue (Tables)
Revenue (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Disaggregation of Revenue [Table Text Block] | DPL's revenue from contracts with customers was $743.8 million for the year ended December 31, 2018 . The following table presents our revenue from contracts with customers and other revenue by segment for the year ended December 31, 2018 : $ in millions Utility Other Adjustments and Eliminations Total Year ended December 31, 2018 Retail Revenue Retail revenue from contracts with customers $ 625.8 $ — $ (1.0 ) $ 624.8 Other retail revenues (a) 32.1 — — 32.1 Wholesale Revenue Wholesale revenue from contracts with customers 29.9 22.1 — 52.0 RTO revenue 43.1 0.1 — 43.2 RTO capacity revenues 7.8 6.6 — 14.4 Other revenues from contracts with customers (b) — 9.4 — 9.4 Other revenues — 2.8 (2.8 ) — Total revenues $ 738.7 $ 41.0 $ (3.8 ) $ 775.9 (a) Other retail revenue primarily includes alternative revenue programs not accounted for under FASC 606. (b) Other revenues from contracts with customers primarily includes revenues for various services provided by Miami Valley Lighting. |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
Disaggregation of Revenue [Table Text Block] | DP&L's revenue from contracts with customers was $706.6 million for the year ended December 31, 2018 . The following table presents our revenue from contracts with customers and other revenue by segment for the year ended December 31, 2018 : Year ended December 31, $ in millions 2018 Retail Revenue Retail revenue from contracts with customers $ 625.8 Other retail revenues (a) 32.1 Wholesale Revenue Wholesale revenue from contracts with customers 29.9 RTO revenue 43.1 RTO capacity revenues 7.8 Total revenues $ 738.7 (a) Other retail revenue primarily includes alternative revenue programs not accounted for under FASC 606. |
Discontinued Operations (Tables
Discontinued Operations (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
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 major categories of assets and liabilities at the dates indicated: $ in millions December 31, 2018 December 31, 2017 Restricted cash $ — $ 1.5 Accounts receivable, net 4.0 37.9 Inventories — 19.4 Taxes applicable to subsequent years 2.3 7.4 Other prepayments and current assets 2.4 17.4 Property, plant & equipment, net — 232.2 Intangible assets, net 5.3 5.5 Other deferred assets — 0.6 Total assets of the disposal group classified as assets of discontinued operations and held-for-sale businesses in the balance sheets $ 14.0 $ 321.9 Accounts payable $ 3.9 $ 25.1 Accrued taxes 3.1 6.3 Other current liabilities 5.2 30.0 Long-term debt (a) — 0.3 Deferred taxes (b) (39.8 ) (2.3 ) Taxes payable 2.3 7.4 Pension, retiree and other benefits 9.7 10.6 Asset retirement obligations 90.4 116.6 Other deferred credits 6.6 5.9 Total liabilities of the disposal group classified as liabilities of discontinued operations and held-for-sale businesses in the balance sheets $ 81.4 $ 199.9 (a) Long-term debt relates to capital leases. (b) Deferred taxes represent the tax asset position of the discontinued group of components, which were netted with liabilities on DPL prior to classification as discontinued operations. The following table summarizes the revenues, cost of revenues, operating and other expenses and income tax of discontinued operations for the periods indicated: Years ended December 31, $ in millions 2018 2017 2016 Revenues $ 158.6 $ 492.9 $ 593.0 Cost of revenues (74.3 ) (249.5 ) (349.6 ) Operating and other expenses (13.8 ) (195.0 ) (214.6 ) Fixed-asset impairment — (175.8 ) (835.2 ) Income / (loss) from discontinued operations 70.5 (127.4 ) (806.4 ) Gain / (loss) from disposal of discontinued operations (1.6 ) 14.0 49.2 Income tax expense / (benefit) from discontinued operations 30.0 (20.3 ) (257.2 ) Net income / (loss) from discontinued operations $ 38.9 $ (93.1 ) $ (500.0 ) |
Generation Separation (Tables)
Generation Separation (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
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 major categories of assets and liabilities at the dates indicated: $ in millions December 31, 2018 December 31, 2017 Restricted cash $ — $ 1.5 Accounts receivable, net 4.0 37.9 Inventories — 19.4 Taxes applicable to subsequent years 2.3 7.4 Other prepayments and current assets 2.4 17.4 Property, plant & equipment, net — 232.2 Intangible assets, net 5.3 5.5 Other deferred assets — 0.6 Total assets of the disposal group classified as assets of discontinued operations and held-for-sale businesses in the balance sheets $ 14.0 $ 321.9 Accounts payable $ 3.9 $ 25.1 Accrued taxes 3.1 6.3 Other current liabilities 5.2 30.0 Long-term debt (a) — 0.3 Deferred taxes (b) (39.8 ) (2.3 ) Taxes payable 2.3 7.4 Pension, retiree and other benefits 9.7 10.6 Asset retirement obligations 90.4 116.6 Other deferred credits 6.6 5.9 Total liabilities of the disposal group classified as liabilities of discontinued operations and held-for-sale businesses in the balance sheets $ 81.4 $ 199.9 (a) Long-term debt relates to capital leases. (b) Deferred taxes represent the tax asset position of the discontinued group of components, which were netted with liabilities on DPL prior to classification as discontinued operations. The following table summarizes the revenues, cost of revenues, operating and other expenses and income tax of discontinued operations for the periods indicated: Years ended December 31, $ in millions 2018 2017 2016 Revenues $ 158.6 $ 492.9 $ 593.0 Cost of revenues (74.3 ) (249.5 ) (349.6 ) Operating and other expenses (13.8 ) (195.0 ) (214.6 ) Fixed-asset impairment — (175.8 ) (835.2 ) Income / (loss) from discontinued operations 70.5 (127.4 ) (806.4 ) Gain / (loss) from disposal of discontinued operations (1.6 ) 14.0 49.2 Income tax expense / (benefit) from discontinued operations 30.0 (20.3 ) (257.2 ) Net income / (loss) from discontinued operations $ 38.9 $ (93.1 ) $ (500.0 ) |
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 and 2016. The following table summarizes the revenues, cost of revenues, operating and other expenses and income tax of discontinued operations for the periods indicated: Years ended December 31, $ in millions 2017 2016 Revenues $ 358.4 $ 557.9 Cost of revenues (191.6 ) (341.1 ) Operating and other expenses (156.8 ) (202.0 ) Fixed-asset impairment (66.3 ) (1,353.5 ) Loss from discontinued operations (56.3 ) (1,338.7 ) Income tax benefit from discontinued operations (15.9 ) (468.4 ) Net loss from discontinued operations $ (40.4 ) $ (870.3 ) |
Assets and Liabilities Held-F_2
Assets and Liabilities Held-For-Sale and Dispositions (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
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 major categories of assets and liabilities at the dates indicated: $ in millions December 31, 2018 December 31, 2017 Restricted cash $ — $ 1.5 Accounts receivable, net 4.0 37.9 Inventories — 19.4 Taxes applicable to subsequent years 2.3 7.4 Other prepayments and current assets 2.4 17.4 Property, plant & equipment, net — 232.2 Intangible assets, net 5.3 5.5 Other deferred assets — 0.6 Total assets of the disposal group classified as assets of discontinued operations and held-for-sale businesses in the balance sheets $ 14.0 $ 321.9 Accounts payable $ 3.9 $ 25.1 Accrued taxes 3.1 6.3 Other current liabilities 5.2 30.0 Long-term debt (a) — 0.3 Deferred taxes (b) (39.8 ) (2.3 ) Taxes payable 2.3 7.4 Pension, retiree and other benefits 9.7 10.6 Asset retirement obligations 90.4 116.6 Other deferred credits 6.6 5.9 Total liabilities of the disposal group classified as liabilities of discontinued operations and held-for-sale businesses in the balance sheets $ 81.4 $ 199.9 (a) Long-term debt relates to capital leases. (b) Deferred taxes represent the tax asset position of the discontinued group of components, which were netted with liabilities on DPL prior to classification as discontinued operations. The following table summarizes the revenues, cost of revenues, operating and other expenses and income tax of discontinued operations for the periods indicated: Years ended December 31, $ in millions 2018 2017 2016 Revenues $ 158.6 $ 492.9 $ 593.0 Cost of revenues (74.3 ) (249.5 ) (349.6 ) Operating and other expenses (13.8 ) (195.0 ) (214.6 ) Fixed-asset impairment — (175.8 ) (835.2 ) Income / (loss) from discontinued operations 70.5 (127.4 ) (806.4 ) Gain / (loss) from disposal of discontinued operations (1.6 ) 14.0 49.2 Income tax expense / (benefit) from discontinued operations 30.0 (20.3 ) (257.2 ) Net income / (loss) from discontinued operations $ 38.9 $ (93.1 ) $ (500.0 ) |
Overview and Summary of Signi_4
Overview and Summary of Significant Accounting Policies (Narrative) (Details) $ in Millions | Jan. 31, 2019employee | Jan. 01, 2018USD ($) | Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($)mi²segmentcustomer | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) |
Significant Accounting Policies [Line Items] | |||||||
Other Investments | $ 0.2 | $ 0.3 | |||||
Cash and Cash Equivalents, at Carrying Value | 90.5 | 24.5 | |||||
Restricted Cash and Cash Equivalents, Current | 21.2 | 0.4 | |||||
Capitalized Software, estimated amortization expense for year after next | $ 3.2 | ||||||
Number of reportable segments | segment | 1 | ||||||
Service area, square miles | mi² | 6,000 | ||||||
Capitalized interest for unregulated generation property | $ 0.5 | $ 1.7 | $ 2.1 | ||||
Straight-line depreciation average annual composite basis (percent) | 4.30% | 5.00% | 6.10% | ||||
Depreciation and amortization | $ 73.1 | $ 76.1 | $ 73.6 | ||||
Insurance and claims costs | 4.1 | 3 | |||||
Insurance costs below coverage thresholds of third-party providers | $ 4.3 | 4.4 | |||||
Finite-Lived Intangible Asset, Useful Life | 7 years | ||||||
Capitalized Computer Software, Amortization | $ 6.6 | 5.7 | 6.6 | ||||
Capitalized Software, estimated amortization over remaining useful life | 15 | ||||||
Capitalized Software, estimated amortization expense for next twelve months | 4.2 | ||||||
Capitalized Software, estimated amortization expense for three years in the future | 3 | ||||||
Capitalized Software, estimated amortization expense for four years in the future | 2.6 | ||||||
Capitalized Software, estimated amortization expense for five years in the future | 2 | ||||||
AOCI reclassed to Retained Earnings before tax | $ 1.6 | ||||||
AOCI reclassed to Retained Earnings, net of tax | 1 | (1) | |||||
Restricted Cash and Cash Equivalents | 111.7 | 24.9 | 54.6 | $ 80.3 | |||
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||
Significant Accounting Policies [Line Items] | |||||||
Cash and Cash Equivalents, at Carrying Value | 45 | 5.2 | |||||
Restricted Cash and Cash Equivalents, Current | 21.2 | 0.4 | |||||
Payments of Ordinary Dividends, Common Stock | 43.8 | 39 | 70 | ||||
Capitalized Software, estimated amortization expense for year after next | $ 2.4 | ||||||
Approximate number of retail customers | customer | 525,000 | ||||||
Service area, square miles | mi² | 6,000 | ||||||
Capitalized interest for unregulated generation property | $ 0.5 | $ 1.5 | $ 2 | ||||
Straight-line depreciation average annual composite basis (percent) | 3.00% | 3.40% | 4.60% | ||||
Depreciation and amortization | $ 74.5 | $ 75.3 | $ 71 | ||||
Insurance costs below coverage thresholds of third-party providers | $ 4.3 | 4.4 | |||||
Finite-Lived Intangible Asset, Useful Life | 7 years | ||||||
Capitalized Computer Software, Amortization | $ 6.3 | 5.7 | 6.7 | ||||
Capitalized Software, estimated amortization over remaining useful life | 11.1 | ||||||
Capitalized Software, estimated amortization expense for next twelve months | 3.5 | ||||||
Capitalized Software, estimated amortization expense for three years in the future | 2.2 | ||||||
Capitalized Software, estimated amortization expense for four years in the future | 1.8 | ||||||
Capitalized Software, estimated amortization expense for five years in the future | 1.2 | ||||||
AOCI reclassed to Retained Earnings before tax | 1.7 | ||||||
AOCI reclassed to Retained Earnings, net of tax | $ 1.1 | (1.1) | |||||
Restricted Cash and Cash Equivalents | 66.2 | 5.6 | 1.6 | $ 5.4 | |||
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 | 659 | ||||||
Employees under collective bargaining agreement (percent) | 57.00% | ||||||
Subsequent Event [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||
Significant Accounting Policies [Line Items] | |||||||
Entity number of employees | employee | 647 | ||||||
Percentage Of Employees Under Collective Bargaining Agreement | 58.00% | ||||||
Electric Generation, Transmission and Distribution Equipment [Member] | |||||||
Significant Accounting Policies [Line Items] | |||||||
Depreciation and amortization | 66.5 | 70.4 | 67 | ||||
Electric Generation, Transmission and Distribution Equipment [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||
Significant Accounting Policies [Line Items] | |||||||
Depreciation and amortization | 68.2 | 69.6 | 64.3 | ||||
Pension [Member] | |||||||
Significant Accounting Policies [Line Items] | |||||||
Service cost | 6.1 | 5.7 | 5.7 | ||||
Interest cost | 13.8 | 14.2 | 14.7 | ||||
Pension [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||
Significant Accounting Policies [Line Items] | |||||||
Service cost | 6.1 | 5.7 | 5.7 | ||||
Interest cost | 13.8 | 14.2 | 14.7 | ||||
Pension [Member] | Scenario, Forecast [Member] | |||||||
Significant Accounting Policies [Line Items] | |||||||
Service cost | $ 5.4 | ||||||
Pension [Member] | Scenario, Forecast [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||
Significant Accounting Policies [Line Items] | |||||||
Service cost | $ 5.4 | ||||||
Adjustments for New Accounting Pronouncement [Member] | |||||||
Significant Accounting Policies [Line Items] | |||||||
Non-service Pension Costs | 2.2 | 3.2 | |||||
Increase (Decrease) in Restricted Cash | 27.1 | (11.8) | |||||
AOCI reclassed to Retained Earnings before tax | 1.6 | ||||||
AOCI reclassed to Retained Earnings, net of tax | 1 | ||||||
Adjustments for New Accounting Pronouncement [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||
Significant Accounting Policies [Line Items] | |||||||
Non-service Pension Costs | (1.5) | (0.9) | |||||
Increase (Decrease) in Restricted Cash | $ 26.6 | $ (11.9) | |||||
AOCI reclassed to Retained Earnings before tax | 1.7 | ||||||
AOCI reclassed to Retained Earnings, net of tax | $ 1.1 |
Overview and Summary of Signi_5
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, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Excise Taxes Collected | $ 51.7 | $ 49.4 | $ 50.9 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Excise Taxes Collected | $ 51.7 | $ 49.4 | $ 50.9 |
Supplemental Financial Inform_3
Supplemental Financial Information (Supplemental Financial Information) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Aug. 01, 2018 | |
Supplemental Financial Information [Line Items] | ||||
Unbilled revenue | $ 16.8 | $ 18 | ||
Customer receivables | 55.8 | 45.2 | ||
Due from PJM transmission settlement | 16.5 | 0 | $ 41.6 | |
Other | 2.3 | 2.5 | ||
Provision for uncollectible accounts | (0.9) | (1.1) | ||
Total accounts receivable, net | 90.5 | 64.6 | ||
Fuel and Limestone | 1.9 | 4.1 | ||
Plant materials and supplies | 8.3 | 8.1 | ||
Other | 0.5 | 0.5 | ||
Total inventories, at average cost | 10.7 | 12.7 | ||
Assets held for sale - current | 8.7 | 315.6 | ||
Gain (Loss) on Disposition of Business | 11.7 | 0 | $ 0 | |
Gain (Loss) on Sale of Assets and Asset Impairment Charges | (2) | 16.1 | (0.1) | |
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Supplemental Financial Information [Line Items] | ||||
Unbilled revenue | 16.8 | 18 | ||
Customer receivables | 53.3 | 44.2 | ||
Amounts due from partners in jointly owned stations | 0 | 5 | ||
Due from PJM transmission settlement | 16.5 | 0 | $ 41.6 | |
Amounts due from affiliates | 2.3 | 0.6 | ||
Other | 2.4 | 4.1 | ||
Provision for uncollectible accounts | (0.9) | (1.1) | ||
Total accounts receivable, net | 90.4 | 70.8 | ||
Plant materials and supplies | 7.1 | 6.9 | ||
Other | 0.6 | 0.4 | ||
Total inventories, at average cost | 7.7 | 7.3 | ||
Gain (Loss) on Disposition of Business | 12.4 | 0 | 0 | |
Gain (Loss) on Sale of Assets and Asset Impairment Charges | $ 0.2 | $ 15.7 | $ (0.1) |
Supplemental Financial Inform_4
Supplemental Financial Information (Reclassification out of ACOI) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||
Other deductions | $ (103.6) | $ (111.7) | $ (106.6) |
Interest expense | (98) | (110) | (107.4) |
Tax expense (benefit) | (0.7) | 5 | 2.4 |
Income / (loss) from discontinued operations before income tax | 70.5 | (127.4) | (806.4) |
Income tax expense from discontinued operations | (30) | 20.3 | 257.2 |
Net income (loss) | 70.1 | (94.6) | (485.2) |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||
Other deductions | (30.7) | (33.6) | (25.4) |
Interest expense | (27.3) | (30.5) | (24.7) |
Tax expense (benefit) | (17.7) | (31.1) | (46) |
Income / (loss) from discontinued operations before income tax | 0 | (56.3) | (1,338.7) |
Income tax expense from discontinued operations | 0 | 15.9 | 468.4 |
Net income (loss) | 86.7 | 17 | (772.7) |
Reclassification out of Accumulated Other Comprehensive Income [Member] | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||
Net income (loss) | 3 | (7.1) | (28.7) |
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) | 2.6 | (1.8) | (24.1) |
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 | (0.1) | 0 |
Tax expense (benefit) | 0 | 0 | 0 |
Net income (loss) | 0 | (0.1) | 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 | (0.1) | 0 |
Tax expense (benefit) | 0 | 0 | 0 |
Net income (loss) | 0 | (0.1) | 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 | (1.2) | (1) | (1) |
Tax expense (benefit) | 0.4 | 0.3 | 0.5 |
Income / (loss) from discontinued operations before income tax | 4.4 | (11.4) | (45.4) |
Income tax expense from discontinued operations | (1.2) | 4.1 | 16.2 |
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax | 3.2 | (7.3) | (29.2) |
Net income (loss) | (0.8) | (0.7) | (0.5) |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||
Interest expense | (1.1) | (0.9) | (1) |
Tax expense (benefit) | 0.4 | 0.2 | 0.2 |
Income / (loss) from discontinued operations before income tax | 0 | (8.5) | (45.4) |
Income tax expense from discontinued operations | 0 | 3 | 16.2 |
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax | 0 | (5.5) | (29.2) |
Net income (loss) | (0.7) | (0.7) | (0.8) |
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 | 0.8 | 1.5 | 1.6 |
Tax expense (benefit) | (0.2) | (0.5) | (0.6) |
Net income (loss) | 0.6 | 1 | 1 |
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 | 4.3 | 6.8 | 7.7 |
Tax expense (benefit) | (1) | (2.3) | (1.8) |
Net income (loss) | $ 3.3 | $ 4.5 | $ 5.9 |
Supplemental Financial Inform_5
Supplemental Financial Information (Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions | Jan. 01, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Other deductions | $ (103.6) | $ (111.7) | $ (106.6) | |
AOCI reclassed to Retained Earnings before tax | $ 1.6 | |||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||
Balance, beginning of period | 0.8 | 0.8 | 0.3 | |
Other comprehensive income / (loss) before reclassifications | (0.6) | 7.6 | ||
Amounts reclassified from accumulated other comprehensive income / (loss) | 3 | (7.1) | ||
Other comprehensive income / (loss) | 2.4 | 0.5 | (17.1) | |
Balance, end of period | 2.2 | 0.8 | 0.3 | |
AOCI reclassed to Retained Earnings, net of tax | 1 | (1) | ||
Income Tax Expense (Benefit) | 0.7 | (5) | (2.4) | |
Net income (loss) | 70.1 | (94.6) | (485.2) | |
Interest and Debt Expense | 98 | 110 | 107.4 | |
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax | 70.5 | (127.4) | (806.4) | |
Income tax expense / (benefit) from discontinued operations | 30 | (20.3) | (257.2) | |
Revenues | 775.9 | |||
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Other deductions | (30.7) | (33.6) | (25.4) | |
AOCI reclassed to Retained Earnings before tax | 1.7 | |||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||
Balance, beginning of period | (36.2) | (36.2) | (42.5) | |
Other comprehensive income / (loss) before reclassifications | (0.6) | 10.2 | ||
Stockholders' Equity Note, Spinoff Transaction | (2.1) | |||
Amounts reclassified from accumulated other comprehensive income / (loss) | 2.6 | (1.8) | ||
Other comprehensive income / (loss) | 2 | 8.4 | (13.8) | |
Balance, end of period | (35.3) | (36.2) | (42.5) | |
AOCI reclassed to Retained Earnings, net of tax | 1.1 | (1.1) | ||
Income Tax Expense (Benefit) | 17.7 | 31.1 | 46 | |
Net income (loss) | 86.7 | 17 | (772.7) | |
Interest and Debt Expense | 27.3 | 30.5 | 24.7 | |
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax | 0 | (56.3) | (1,338.7) | |
Income tax expense / (benefit) from discontinued operations | 0 | (15.9) | (468.4) | |
Revenues | 738.7 | |||
Accumulated Net Investment Gain (Loss) Attributable to Parent [Member] | ||||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||
Balance, beginning of period | 1 | 1 | 0.6 | |
Other comprehensive income / (loss) before reclassifications | 0 | 0.5 | ||
Amounts reclassified from accumulated other comprehensive income / (loss) | 0 | (0.1) | ||
Other comprehensive income / (loss) | 0 | 0.4 | ||
Balance, end of period | 0 | 1 | 0.6 | |
AOCI reclassed to Retained Earnings, net of tax | (1) | |||
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 | 1.1 | 1.1 | 0.7 | |
Other comprehensive income / (loss) before reclassifications | 0 | 0.5 | ||
Stockholders' Equity Note, Spinoff Transaction | 0 | |||
Amounts reclassified from accumulated other comprehensive income / (loss) | 0 | (0.1) | ||
Other comprehensive income / (loss) | 0 | 0.4 | ||
Balance, end of period | 0 | 1.1 | 0.7 | |
AOCI reclassed to Retained Earnings, net of tax | (1.1) | |||
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 | 14.7 | 14.7 | 13.1 | |
Other comprehensive income / (loss) before reclassifications | (0.1) | 9.6 | ||
Amounts reclassified from accumulated other comprehensive income / (loss) | 2.4 | (8) | ||
Other comprehensive income / (loss) | 2.3 | 1.6 | ||
Balance, end of period | 17 | 14.7 | 13.1 | |
AOCI reclassed to Retained Earnings, net of tax | 0 | |||
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 | 1.4 | 1.4 | (2.7) | |
Other comprehensive income / (loss) before reclassifications | (0.1) | 12.4 | ||
Stockholders' Equity Note, Spinoff Transaction | (2.1) | |||
Amounts reclassified from accumulated other comprehensive income / (loss) | (0.7) | (6.2) | ||
Other comprehensive income / (loss) | (0.8) | 6.2 | ||
Balance, end of period | 0.6 | 1.4 | (2.7) | |
AOCI reclassed to Retained Earnings, net of tax | 0 | |||
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] | ||||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||
Balance, beginning of period | (14.9) | (14.9) | (13.4) | |
Other comprehensive income / (loss) before reclassifications | (0.5) | (2.5) | ||
Amounts reclassified from accumulated other comprehensive income / (loss) | 0.6 | 1 | ||
Other comprehensive income / (loss) | 0.1 | (1.5) | ||
Balance, end of period | (14.8) | (14.9) | (13.4) | |
AOCI reclassed to Retained Earnings, net of tax | 0 | |||
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 | $ (38.7) | (38.7) | (40.5) | |
Other comprehensive income / (loss) before reclassifications | (0.5) | (2.7) | ||
Stockholders' Equity Note, Spinoff Transaction | 0 | |||
Amounts reclassified from accumulated other comprehensive income / (loss) | 3.3 | 4.5 | ||
Other comprehensive income / (loss) | 2.8 | 1.8 | ||
Balance, end of period | (35.9) | (38.7) | (40.5) | |
AOCI reclassed to Retained Earnings, net of tax | 0 | |||
Adjustments for New Accounting Pronouncement [Member] | ||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
AOCI reclassed to Retained Earnings before tax | 1.6 | |||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||
AOCI reclassed to Retained Earnings, net of tax | 1 | |||
Adjustments for New Accounting Pronouncement [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
AOCI reclassed to Retained Earnings before tax | 1.7 | |||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||
AOCI reclassed to Retained Earnings, net of tax | 1.1 | |||
Reclassification out of Accumulated Other Comprehensive Income [Member] | ||||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||
Net income (loss) | 3 | (7.1) | (28.7) | |
Reclassification out of Accumulated Other Comprehensive Income [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||
Net income (loss) | 2.6 | (1.8) | (24.1) | |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Investment Gain (Loss) Attributable to Parent [Member] | ||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Other deductions | 0 | (0.1) | 0 | |
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||
Income Tax Expense (Benefit) | 0 | 0 | 0 | |
Net income (loss) | 0 | (0.1) | 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] | ||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Other deductions | 0 | (0.1) | 0 | |
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||
Income Tax Expense (Benefit) | 0 | 0 | 0 | |
Net income (loss) | 0 | (0.1) | 0 | |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | ||||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||
Income Tax Expense (Benefit) | (0.4) | (0.3) | (0.5) | |
Net income (loss) | (0.8) | (0.7) | (0.5) | |
Interest and Debt Expense | 1.2 | 1 | 1 | |
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax | 4.4 | (11.4) | (45.4) | |
Income tax expense / (benefit) from discontinued operations | 1.2 | (4.1) | (16.2) | |
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax | 3.2 | (7.3) | (29.2) | |
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] | ||||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||
Income Tax Expense (Benefit) | (0.4) | (0.2) | (0.2) | |
Net income (loss) | (0.7) | (0.7) | (0.8) | |
Interest and Debt Expense | 1.1 | 0.9 | 1 | |
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax | 0 | (8.5) | (45.4) | |
Income tax expense / (benefit) from discontinued operations | 0 | (3) | (16.2) | |
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax | 0 | (5.5) | (29.2) | |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] | ||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Other deductions | 0.8 | 1.5 | 1.6 | |
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||
Income Tax Expense (Benefit) | 0.2 | 0.5 | 0.6 | |
Net income (loss) | 0.6 | 1 | 1 | |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Other deductions | 4.3 | 6.8 | 7.7 | |
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||
Income Tax Expense (Benefit) | 1 | 2.3 | 1.8 | |
Net income (loss) | 3.3 | 4.5 | 5.9 | |
Electricity [Member] | ||||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||
Revenues | 775.9 | 743.9 | 834.2 | |
Cost of Goods and Services Sold | 322.5 | 300 | 336.5 | |
Electricity [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||
Revenues | 738.7 | 720 | 808 | |
Cost of Goods and Services Sold | 303.7 | 290.3 | 322 | |
Electricity, Purchased [Member] | ||||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||
Cost of Goods and Services Sold | 305 | 291 | 319.1 | |
Electricity, Purchased [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||
Cost of Goods and Services Sold | $ 301.3 | $ 289.8 | $ 316.7 |
Regulatory Matters (Details)
Regulatory Matters (Details) - USD ($) $ in Millions | Jan. 22, 2019 | Oct. 01, 2018 | Oct. 20, 2017 | Jan. 30, 2017 | Dec. 31, 2018 | Sep. 30, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Aug. 01, 2018 | Dec. 31, 2017 |
Regulatory assets earning a return | $ 5.5 | $ 5.5 | ||||||||
Distribution Modernization Rider Period | 3 years | |||||||||
DRO revenue requirement | $ 248 | |||||||||
Regulatory Assets, Noncurrent | 152.6 | 152.6 | $ 163.2 | |||||||
Distribution Modernization Plan Cost of capital projects | 576 | |||||||||
Regulatory Assets, Current | 41.1 | 41.1 | 23.9 | |||||||
Regulatory Assets | 193.7 | 193.7 | 187.1 | |||||||
Regulatory Liability, Noncurrent | 278.3 | 278.3 | 221.2 | |||||||
Regulatory Liability, Current | 34.9 | 34.9 | 14.8 | |||||||
Regulatory Liabilities | 313.2 | 313.2 | 236 | |||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 29.8 | |||||||||
Public Utilities, Approved Return on Equity, Percentage | 9.999% | |||||||||
Public Utilities, Approved Debt Capital Structure, Percentage | 4.80% | |||||||||
Distribution Investment Rider | $ 12.2 | |||||||||
One-time Decoupling Rider Revenue Requirement | $ 3.7 | |||||||||
TCJA Yearly Refund to Customers Per DRO | 4 | |||||||||
DRO Vegetation Management Cost Baseline | 10.7 | |||||||||
DRO Vegetation Management Cost Deferral Cap | $ 4.6 | |||||||||
Distribution Modernization Rider | $ 105 | |||||||||
Return on Equity SEET Threshold | 12.00% | |||||||||
Proposed annual reduction in transmission rates to reflect effects of TCJA | $ 2.4 | |||||||||
Due from PJM transmission settlement | 16.5 | 16.5 | $ 41.6 | 0 | ||||||
PJM transmission enhancement repayment amount | $ 14.3 | |||||||||
Tax rate after Tax Cuts and Jobs Act of 2017 | 21.00% | |||||||||
Vegetation Management and Other [Member] | ||||||||||
Regulatory Assets, Noncurrent | 7.8 | $ 7.8 | ||||||||
Undercollections to be collected [Member] | ||||||||||
Regulatory Assets Type of Recovery | A/B | |||||||||
Regulatory Current Asset, End Date for Recovery | 2,019 | |||||||||
Regulatory Assets, Current | 40.5 | $ 40.5 | 23.9 | |||||||
Amounts being recovered through base rates [Member] | ||||||||||
Regulatory Assets Type of Recovery | B | |||||||||
Regulatory Current Asset, End Date for Recovery | 2,019 | |||||||||
Regulatory Assets, Current | 0.6 | $ 0.6 | 0 | |||||||
Pension Costs [Member] | ||||||||||
Regulatory Assets Type of Recovery | B | |||||||||
Regulatory Current Asset, End Date for Recovery | Ongoing | |||||||||
Regulatory Assets, Noncurrent | 87.5 | $ 87.5 | 92.4 | |||||||
Unrecovered OVEC Charges [Member] | ||||||||||
Regulatory Assets Type of Recovery | C | |||||||||
Regulatory Current Asset, End Date for Recovery | Undetermined | |||||||||
Regulatory Assets, Noncurrent | 28.7 | $ 28.7 | 27.8 | |||||||
Deferred Fuel Costs [Member] | ||||||||||
Regulatory Assets Type of Recovery | B | |||||||||
Regulatory Current Asset, End Date for Recovery | 2,020 | |||||||||
Regulatory Assets, Noncurrent | 3.3 | $ 3.3 | 9.3 | |||||||
Deferred Regulatory Compliance Costs [Member] | ||||||||||
Regulatory Assets Type of Recovery | B | |||||||||
Regulatory Current Asset, End Date for Recovery | 2,020 | |||||||||
Regulatory Assets, Noncurrent | 6.1 | $ 6.1 | 9.2 | |||||||
Ccem Smart Grid And Advanced Metering Infrastructure Cost [Member] | ||||||||||
Regulatory Assets Type of Recovery | B | |||||||||
Regulatory Current Asset, End Date for Recovery | Undetermined | |||||||||
Regulatory Assets, Noncurrent | 8.5 | $ 8.5 | 7.3 | |||||||
Loss on Reacquired Debt [Member] | ||||||||||
Regulatory Assets Type of Recovery | B | |||||||||
Regulatory Current Asset, End Date for Recovery | Various | |||||||||
Regulatory Assets, Noncurrent | 6 | $ 6 | 7 | |||||||
Storm Costs [Member] | ||||||||||
Regulatory Assets Type of Recovery | A | |||||||||
Regulatory Current Asset, End Date for Recovery | Undetermined | |||||||||
Regulatory Assets, Noncurrent | 4.7 | $ 4.7 | 2.1 | |||||||
Vegetation Management [Member] | ||||||||||
Regulatory Assets Type of Recovery | A/B | |||||||||
Regulatory Current Asset, End Date for Recovery | Undetermined | |||||||||
Regulatory Assets, Noncurrent | 4.6 | $ 4.6 | 8.1 | |||||||
Subsidiaries [Member] | ||||||||||
Regulatory assets earning a return | 5.5 | 5.5 | ||||||||
Distribution Modernization Rider Period | 3 years | |||||||||
DRO revenue requirement | 248 | |||||||||
Regulatory Assets, Noncurrent | 152.6 | 152.6 | 163.2 | |||||||
Distribution Modernization Plan Cost of capital projects | 576 | |||||||||
Regulatory Assets, Current | 41.1 | 41.1 | 23.9 | |||||||
Regulatory Assets | 193.7 | 193.7 | 187.1 | |||||||
Regulatory Liability, Noncurrent | 278.3 | 278.3 | 221.2 | |||||||
Regulatory Liability, Current | 34.9 | 34.9 | 14.8 | |||||||
Regulatory Liabilities | 313.2 | 313.2 | 236 | |||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 29.8 | |||||||||
Public Utilities, Approved Return on Equity, Percentage | 9.999% | |||||||||
Public Utilities, Approved Debt Capital Structure, Percentage | 4.80% | |||||||||
Distribution Investment Rider | $ 12.2 | |||||||||
One-time Decoupling Rider Revenue Requirement | $ 3.7 | |||||||||
TCJA Yearly Refund to Customers Per DRO | $ 4 | |||||||||
DRO Vegetation Management Cost Deferral Cap | $ 4.6 | |||||||||
Distribution Modernization Rider | $ 105 | |||||||||
Return on Equity SEET Threshold | 12.00% | |||||||||
Proposed annual reduction in transmission rates to reflect effects of TCJA | $ 2.4 | |||||||||
Due from PJM transmission settlement | 16.5 | 16.5 | $ 41.6 | 0 | ||||||
PJM transmission enhancement repayment amount | $ 14.3 | |||||||||
Tax rate after Tax Cuts and Jobs Act of 2017 | 21.00% | |||||||||
Subsidiaries [Member] | Vegetation Management and Other [Member] | ||||||||||
Regulatory Assets, Noncurrent | 7.8 | $ 7.8 | ||||||||
Subsidiaries [Member] | Undercollections to be collected [Member] | ||||||||||
Regulatory Assets Type of Recovery | A/B | |||||||||
Regulatory Current Asset, End Date for Recovery | 2,019 | |||||||||
Regulatory Assets, Current | 40.5 | $ 40.5 | 23.9 | |||||||
Subsidiaries [Member] | Amounts being recovered through base rates [Member] | ||||||||||
Regulatory Assets Type of Recovery | B | |||||||||
Regulatory Current Asset, End Date for Recovery | 2,019 | |||||||||
Regulatory Assets, Current | 0.6 | $ 0.6 | 0 | |||||||
Subsidiaries [Member] | Pension Costs [Member] | ||||||||||
Regulatory Assets Type of Recovery | B | |||||||||
Regulatory Current Asset, End Date for Recovery | Ongoing | |||||||||
Regulatory Assets, Noncurrent | 87.5 | $ 87.5 | 92.4 | |||||||
Subsidiaries [Member] | Unrecovered OVEC Charges [Member] | ||||||||||
Regulatory Assets Type of Recovery | C | |||||||||
Regulatory Current Asset, End Date for Recovery | Undetermined | |||||||||
Regulatory Assets, Noncurrent | 28.7 | $ 28.7 | 27.8 | |||||||
Subsidiaries [Member] | Deferred Fuel Costs [Member] | ||||||||||
Regulatory Assets Type of Recovery | B | |||||||||
Regulatory Current Asset, End Date for Recovery | 2,020 | |||||||||
Regulatory Assets, Noncurrent | 3.3 | $ 3.3 | 9.3 | |||||||
Subsidiaries [Member] | Deferred Regulatory Compliance Costs [Member] | ||||||||||
Regulatory Assets Type of Recovery | B | |||||||||
Regulatory Current Asset, End Date for Recovery | 2,020 | |||||||||
Regulatory Assets, Noncurrent | 6.1 | $ 6.1 | 9.2 | |||||||
Subsidiaries [Member] | Ccem Smart Grid And Advanced Metering Infrastructure Cost [Member] | ||||||||||
Regulatory Assets Type of Recovery | B | |||||||||
Regulatory Current Asset, End Date for Recovery | Undetermined | |||||||||
Regulatory Assets, Noncurrent | 8.5 | $ 8.5 | 7.3 | |||||||
Subsidiaries [Member] | Loss on Reacquired Debt [Member] | ||||||||||
Regulatory Assets Type of Recovery | B | |||||||||
Regulatory Current Asset, End Date for Recovery | Various | |||||||||
Regulatory Assets, Noncurrent | 6 | $ 6 | 7 | |||||||
Subsidiaries [Member] | Storm Costs [Member] | ||||||||||
Regulatory Assets Type of Recovery | A | |||||||||
Regulatory Current Asset, End Date for Recovery | Undetermined | |||||||||
Regulatory Assets, Noncurrent | 4.7 | $ 4.7 | 2.1 | |||||||
Subsidiaries [Member] | Vegetation Management [Member] | ||||||||||
Regulatory Assets Type of Recovery | A/B | |||||||||
Regulatory Current Asset, End Date for Recovery | Undetermined | |||||||||
Regulatory Assets, Noncurrent | 4.6 | $ 4.6 | 8.1 | |||||||
Postretirement Benefit Costs [Member] | ||||||||||
Regulatory Liabilities Type of Recovery | B | |||||||||
Regulatory Liability, Amortization Through | Ongoing | |||||||||
Regulatory Liability, Noncurrent | 6 | $ 6 | 5 | |||||||
Postretirement Benefit Costs [Member] | Subsidiaries [Member] | ||||||||||
Regulatory Liabilities Type of Recovery | B | |||||||||
Regulatory Liability, Amortization Through | Ongoing | |||||||||
Regulatory Liability, Noncurrent | 6 | $ 6 | 5 | |||||||
PJM transmission enhancement settlement repayment amount [Member] | ||||||||||
Regulatory Liabilities Type of Recovery | A | |||||||||
Regulatory Liability, Amortization Through | 2,025 | |||||||||
Regulatory Liability, Noncurrent | 16.9 | $ 16.9 | 0 | |||||||
PJM transmission enhancement settlement repayment amount [Member] | Subsidiaries [Member] | ||||||||||
Regulatory Liabilities Type of Recovery | A | |||||||||
Regulatory Liability, Amortization Through | 2,025 | |||||||||
Regulatory Liability, Noncurrent | 16.9 | $ 16.9 | 0 | |||||||
Deferred Income Tax Charge [Member] | ||||||||||
Regulatory Liability, Amortization Through | Various | |||||||||
Regulatory Liability, Noncurrent | 116.3 | $ 116.3 | 83.4 | |||||||
Deferred Income Tax Charge [Member] | Subsidiaries [Member] | ||||||||||
Regulatory Liability, Amortization Through | Various | |||||||||
Regulatory Liability, Noncurrent | 116.3 | $ 116.3 | 83.4 | |||||||
Removal Costs [Member] | ||||||||||
Regulatory Liability, Amortization Through | Not Applicable | |||||||||
Regulatory Liability, Noncurrent | 139.1 | $ 139.1 | 132.8 | |||||||
Removal Costs [Member] | Subsidiaries [Member] | ||||||||||
Regulatory Liability, Amortization Through | Not Applicable | |||||||||
Regulatory Liability, Noncurrent | 139.1 | $ 139.1 | 132.8 | |||||||
Overcollection of costs to be refunded [Member] | ||||||||||
Regulatory Liabilities Type of Recovery | A/B | |||||||||
Regulatory Liability, Amortization Through | 2,019 | |||||||||
Regulatory Liability, Noncurrent | 34.9 | $ 34.9 | 14.8 | |||||||
Overcollection of costs to be refunded [Member] | Subsidiaries [Member] | ||||||||||
Regulatory Liabilities Type of Recovery | A/B | |||||||||
Regulatory Liability, Amortization Through | 2,018 | |||||||||
Regulatory Liability, Noncurrent | 34.9 | $ 34.9 | $ 14.8 | |||||||
Scenario, Forecast [Member] | ||||||||||
Distribution Investment Rider | $ 22 | |||||||||
DRO Vegetation Management Cost Baseline | 15.7 | |||||||||
DRO Vegetation Management Cost Deferral Cap | 4.6 | |||||||||
Requested Distribution Modernization Rider annual revenue through filing | $ 199 | |||||||||
Scenario, Forecast [Member] | Subsidiaries [Member] | ||||||||||
Distribution Investment Rider | 22 | |||||||||
DRO Vegetation Management Cost Baseline | 15.7 | |||||||||
Requested Distribution Modernization Rider annual revenue through filing | $ 199 | |||||||||
Subsequent Event [Member] | Subsidiaries [Member] | ||||||||||
DRO Vegetation Management Cost Deferral Cap | $ 4.6 | |||||||||
Long-term [Member] | ||||||||||
Due from PJM transmission settlement | 10.8 | 10.8 | ||||||||
Long-term [Member] | Subsidiaries [Member] | ||||||||||
Due from PJM transmission settlement | 10.8 | 10.8 | ||||||||
Short-term [Member] | ||||||||||
Due from PJM transmission settlement | 16.5 | 16.5 | ||||||||
Short-term [Member] | Subsidiaries [Member] | ||||||||||
Due from PJM transmission settlement | $ 16.5 | $ 16.5 |
Property, Plant and Equipment w
Property, Plant and Equipment with Corresponding Depreciation Rates (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Public Utility, Property, Plant and Equipment [Line Items] | |||
Total property, plant and equipment in service | $ 1,615.6 | $ 1,544.1 | |
Total property, plant and equipment in service, Composite Rate | 4.30% | 5.00% | 6.10% |
Regulated Operation [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Transmission | $ 223.2 | $ 242.7 | |
Distribution | 1,289.8 | 1,197.5 | |
General | 13.2 | 13.7 | |
Non-depreciable | 60.4 | 64.7 | |
Total property, plant and equipment in service | $ 1,586.6 | $ 1,518.6 | |
Transmission, Composite Rate | 4.10% | 4.00% | |
Distribution, Composite Rate | 4.50% | 4.90% | |
General, Composite Rate | 8.50% | 7.10% | |
Unregulated Operation [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Non-depreciable | $ 7.8 | $ 4.2 | |
Total property, plant and equipment in service | 29 | 25.5 | |
Production / Generation | 0 | 0.2 | |
Other | $ 21.2 | $ 21.1 | |
Other, Composite Rate | 6.70% | 7.00% | |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Total property, plant and equipment in service | $ 2,274.4 | $ 2,247.2 | |
Total property, plant and equipment in service, Composite Rate | 3.00% | 3.40% | 4.60% |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Regulated Operation [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Transmission | $ 386.7 | $ 414.6 | |
Distribution | 1,796.4 | 1,735.9 | |
General | 30.9 | 31.2 | |
Non-depreciable | 60.4 | 64.6 | |
Total property, plant and equipment in service | $ 2,274.4 | $ 2,246.3 | |
Transmission, Composite Rate | 2.40% | 2.40% | |
Distribution, Composite Rate | 3.20% | 3.40% | |
General, Composite Rate | 3.60% | 3.10% | |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Unregulated Operation [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Non-depreciable | $ 0 | $ 0.9 | |
Production / Generation | 0 | $ 0.2 | |
Production/Generation, Composite Rate | 2.70% | ||
Other | $ 0 | $ 0.7 |
Property, Plant and Equipment_2
Property, Plant and Equipment (Narrative) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Jointly Owned Utility Plant Interests [Line Items] | |||
Fixed-asset impairment (Note 14) | $ 2.8 | $ 0 | $ 23.9 |
Estimated costs of removal | 139.1 | 132.8 | 126.5 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Jointly Owned Utility Plant Interests [Line Items] | |||
Fixed-asset impairment (Note 14) | 0 | 66.3 | 1,353.5 |
Estimated costs of removal | $ 139.1 | $ 132.8 | $ 126.5 |
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, 2018 | Dec. 31, 2017 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Balance at January 1 | $ 15.1 | $ 15 |
Asset Retirement Obligation, Revision of Estimate | (2.6) | (0.1) |
Accretion expense | 0.3 | 0.4 |
Settlements | (3.4) | (0.2) |
Balance at December 31 | 9.4 | 15.1 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Balance at January 1 | 8 | 8.2 |
Accretion expense | 0.1 | |
Settlements | (3.3) | (0.3) |
Balance at December 31 | $ 4.7 | $ 8 |
Property, Plant and Equipment_3
Property, Plant and Equipment (Changes in the Liability for Transmission and Distribution Asset Removal Costs) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Changes in Liability for Transmission and Distribution Asset Removal Costs [Roll Forward] | ||
Balance at January 1 | $ 132.8 | $ 126.5 |
Additions | 14.3 | 12 |
Settlements | (8) | (5.7) |
Balance at December 31 | 139.1 | 132.8 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Changes in Liability for Transmission and Distribution Asset Removal Costs [Roll Forward] | ||
Balance at January 1 | 132.8 | 126.5 |
Additions | 14.3 | 12 |
Settlements | (8) | (5.7) |
Balance at December 31 | $ 139.1 | $ 132.8 |
Fair Value Measurements (Narrat
Fair Value Measurements (Narrative) (Details) - USD ($) $ in Millions | Jan. 01, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Asset Retirement Obligations, Noncurrent | $ 9.4 | $ 15.1 | ||
Debt maturity date, earliest | 2,019 | |||
Debt maturity date, latest | 2,061 | |||
Unrealized gains and immaterial losses on Master Trust assets in AOCI, after tax | $ 0 | 0.4 | $ 0.2 | |
Asset Retirement Obligation, Revision of Estimate | 2.6 | 0.1 | ||
Proceeds from Sale of Debt Securities, Available-for-sale | 0.5 | |||
AvailableForSaleSecuritiesGross Realized Gains Losses Sale Proceeds Net of Tax | 0.4 | |||
AOCI reclassed to Retained Earnings before tax | $ 1.6 | |||
AOCI reclassed to Retained Earnings, net of tax | 1 | (1) | ||
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Asset Retirement Obligations, Noncurrent | 4.7 | 8 | ||
Unrealized gains and immaterial losses on Master Trust assets in AOCI, after tax | 0 | $ 0.4 | $ 0.2 | |
AOCI reclassed to Retained Earnings before tax | 1.7 | |||
AOCI reclassed to Retained Earnings, net of tax | $ 1.1 | $ (1.1) |
Fair Value Measurements (Fair V
Fair Value Measurements (Fair Value and Cost of Non-Derivative Instruments) (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Carrying Value [Member] | ||
Total Assets | $ 7.1 | $ 7.3 |
Carrying Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Assets | 7.1 | 7.3 |
Carrying Value [Member] | Money Market Funds [Member] | ||
Total Master Trust Assets, Cost | 0.4 | 0.3 |
Carrying Value [Member] | Money Market Funds [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Cost | 0.4 | 0.3 |
Carrying Value [Member] | Equity Securities [Member] | ||
Total Master Trust Assets, Cost | 2.4 | 2.5 |
Carrying Value [Member] | Equity Securities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Cost | 2.4 | 2.5 |
Carrying Value [Member] | Debt Securities [Member] | ||
Total Master Trust Assets, Cost | 4.1 | 4.3 |
Carrying Value [Member] | Debt Securities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Cost | 4.1 | 4.3 |
Carrying Value [Member] | Hedge Funds [Member] | ||
Total Master Trust Assets, Cost | 0.1 | 0.1 |
Carrying Value [Member] | Hedge Funds [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Cost | 0.1 | 0.1 |
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 | 1,475.9 | 1,704.8 |
Carrying Value [Member] | Debt [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Long-term Debt | 586.1 | 646.6 |
Fair Value [Member] | ||
Total Master Trust Assets, Fair Value | 8.1 | 9.1 |
Total Assets | 8.1 | 9.1 |
Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 8.1 | 9.1 |
Total Assets | 8.1 | 9.1 |
Fair Value [Member] | Money Market Funds [Member] | ||
Total Master Trust Assets, Fair Value | 0.4 | 0.3 |
Fair Value [Member] | Money Market Funds [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0.4 | 0.3 |
Fair Value [Member] | Equity Securities [Member] | ||
Total Master Trust Assets, Fair Value | 3.5 | 4.2 |
Fair Value [Member] | Equity Securities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 3.5 | 4.2 |
Fair Value [Member] | Debt Securities [Member] | ||
Total Master Trust Assets, Fair Value | 4 | 4.3 |
Fair Value [Member] | Debt Securities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 4 | 4.3 |
Fair Value [Member] | Hedge Funds [Member] | ||
Total Master Trust Assets, Fair Value | 0.1 | 0.2 |
Fair Value [Member] | Hedge Funds [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0.1 | 0.2 |
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 | 1,519.6 | 1,819.3 |
Fair Value [Member] | Debt [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Debt, Fair Value | $ 593.8 | $ 658.4 |
Fair Value Measurements (Fair_2
Fair Value Measurements (Fair Value of Assets and Liabilities Measured on Recurring Basis) (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Fair Value, Inputs, Level 1 [Member] | ||
Total Master Trust Assets, Fair Value | $ 0.4 | $ 0.3 |
Total Derivative Assets | 0 | 0 |
Total Assets | 0.4 | 0.3 |
Total Liabilities | 0 | 0 |
Fair Value, Inputs, Level 1 [Member] | Interest Rate Contract [Member] | ||
Total Derivative Assets | 0 | 0 |
Fair Value, Inputs, Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0.4 | 0.3 |
Total Derivative Assets | 0 | 0 |
Total Assets | 0.4 | 0.3 |
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 | 0 |
Fair Value, Inputs, Level 2 [Member] | ||
Total Master Trust Assets, Fair Value | 7.7 | 8.8 |
Total Derivative Assets | 1.5 | 1.5 |
Total Assets | 9.2 | 10.3 |
Total Liabilities | 1,501.9 | 1,801.5 |
Fair Value, Inputs, Level 2 [Member] | Interest Rate Contract [Member] | ||
Total Derivative Assets | 1.5 | 1.5 |
Fair Value, Inputs, Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 7.7 | 8.8 |
Total Derivative Assets | 1.5 | 1.5 |
Total Assets | 9.2 | 10.3 |
Debt Instrument, Fair Value Disclosure | 640.6 | |
Total Liabilities | 576.1 | 640.6 |
Fair Value, Inputs, Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Interest Rate Contract [Member] | ||
Total Derivative Assets | 1.5 | 1.5 |
Fair Value, Inputs, Level 3 [Member] | ||
Total Master Trust Assets, Fair Value | 0 | 0 |
Total Derivative Assets | 0 | 0 |
Total Assets | 0 | 0 |
Total Liabilities | 17.7 | 17.8 |
Fair Value, Inputs, Level 3 [Member] | Interest Rate Contract [Member] | ||
Total Derivative Assets | 0 | 0 |
Fair Value, Inputs, Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Assets | 0 | |
Debt Instrument, Fair Value Disclosure | 17.8 | |
Total Liabilities | 17.7 | 17.8 |
Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Total Master Trust Assets, Fair Value | 0 | 0 |
Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0 | 0 |
Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Total Master Trust Assets, Fair Value | 3.5 | 4.2 |
Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 3.5 | 4.2 |
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 | 4.3 |
Debt Securities [Member] | Fair Value, Inputs, Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 4 | 4.3 |
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 | 0.4 | 0.3 |
Money Market Funds [Member] | Fair Value, Inputs, Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0.4 | 0.3 |
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] | Fair Value, Inputs, Level 1 [Member] | ||
Total Master Trust Assets, Fair Value | 0 | 0 |
Hedge Funds [Member] | Fair Value, Inputs, Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0 | 0 |
Hedge Funds [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Total Master Trust Assets, Fair Value | 0.1 | 0.2 |
Hedge Funds [Member] | Fair Value, Inputs, Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0.1 | 0.2 |
Hedge 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 | 1,501.9 | 1,801.5 |
Debt [Member] | Fair Value, Inputs, Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Debt Instrument, Fair Value Disclosure | 576.1 | |
Debt [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Debt Instrument, Fair Value Disclosure | 17.7 | 17.8 |
Debt [Member] | Fair Value, Inputs, Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Debt Instrument, Fair Value Disclosure | 17.7 | |
Fair Value [Member] | ||
Total Master Trust Assets, Fair Value | 8.1 | 9.1 |
Total Derivative Assets | 1.5 | 1.5 |
Total Assets | 9.6 | 10.6 |
Total Liabilities | 1,519.6 | 1,819.3 |
Fair Value [Member] | Interest Rate Contract [Member] | ||
Total Derivative Assets | 1.5 | 1.5 |
Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 8.1 | 9.1 |
Total Derivative Assets | 1.5 | |
Total Assets | 9.6 | 10.6 |
Total Liabilities | 593.8 | 658.4 |
Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Interest Rate Contract [Member] | ||
Total Derivative Assets | 1.5 | 1.5 |
Fair Value [Member] | Equity Securities [Member] | ||
Total Master Trust Assets, Fair Value | 3.5 | 4.2 |
Fair Value [Member] | Equity Securities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 3.5 | 4.2 |
Fair Value [Member] | Debt Securities [Member] | ||
Total Master Trust Assets, Fair Value | 4 | 4.3 |
Fair Value [Member] | Debt Securities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 4 | 4.3 |
Fair Value [Member] | Money Market Funds [Member] | ||
Total Master Trust Assets, Fair Value | 0.4 | 0.3 |
Fair Value [Member] | Money Market Funds [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0.4 | 0.3 |
Fair Value [Member] | Hedge Funds [Member] | ||
Total Master Trust Assets, Fair Value | 0.1 | 0.2 |
Fair Value [Member] | Hedge Funds [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Total Master Trust Assets, Fair Value | 0.1 | 0.2 |
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 | 1,519.6 | 1,819.3 |
Fair Value [Member] | Debt [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Debt Instrument, Fair Value Disclosure | $ 593.8 | $ 658.4 |
Fair Value Measurements (Fair_3
Fair Value Measurements (Fair Value of Assets and Liabilities Measured on a Nonrecurring Basis) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Carrying Value | $ 1,337 | $ 1,321.5 | |
Fixed-asset impairment (Note 14) | 2.8 | 0 | $ 23.9 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Carrying Value | 1,318.1 | 1,301.4 | |
Fixed-asset impairment (Note 14) | $ 0 | $ 66.3 | 1,353.5 |
Conesville [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Carrying Value | 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 | ||
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 | ||
Conesville [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Fixed-asset impairment (Note 14) | 23.9 | ||
Conesville [Member] | Fair Value, Inputs, Level 3 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Long-lived assets held and used, fair value | $ 1.1 |
Fair Value Measurements (Signif
Fair Value Measurements (Significant unobservable inputs, nonrecurring) (Details) $ in Millions | 3 Months Ended |
Dec. 31, 2016USD ($) | |
Conesville [Member] | Fair Value, Inputs, Level 3 [Member] | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |
Long-lived assets held and used, fair value | $ 1.1 |
Minimum [Member] | Valuation, Income Approach [Member] | Conesville [Member] | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |
Fair Value Inputs, Revenue Growth Rate | (19.30%) |
Fair Value Inputs, Long-term Pre-tax Operating Margin | (54.30%) |
Maximum [Member] | Valuation, Income Approach [Member] | Conesville [Member] | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |
Fair Value Inputs, Revenue Growth Rate | 10.90% |
Fair Value Inputs, Long-term Pre-tax Operating Margin | 99.40% |
Weighted Average [Member] | Valuation, Income Approach [Member] | Conesville [Member] | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |
Fair Value Inputs, Revenue Growth Rate | 0.60% |
Fair Value Inputs, Long-term Pre-tax Operating Margin | 20.20% |
Derivative Instruments and He_3
Derivative Instruments and Hedging Activities (Narrative) (Details) | 12 Months Ended | |||
Dec. 31, 2018USD ($) | Sep. 30, 2018Number_of_interest_rate_swaps | Mar. 29, 2018USD ($) | Dec. 31, 2017USD ($) | |
Sale of Derivative Instruments Interest Rate Swap | $ 60,000,000 | |||
Gain on sale of Derivative Instruments Interest Rate Swap | 800,000 | |||
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Number of Interest Rate Swaps | Number_of_interest_rate_swaps | 2 | |||
Sale of Derivative Instruments Interest Rate Swap | $ 60,000,000 | |||
Gain on sale of Derivative Instruments Interest Rate Swap | 800,000 | |||
Tax-exempt First Mortgage Bonds - rates from: 2.49% - 2.93% (a) and 1.29% - 1.42% (b) | ||||
Long-term Debt, Gross | 140,000,000 | $ 200,000,000 | ||
Tax-exempt First Mortgage Bonds - rates from: 2.49% - 2.93% (a) and 1.29% - 1.42% (b) | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Long-term Debt, Gross | 140,000,000 | 200,000,000 | ||
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | ||||
Derivative, Notional Amount, Purchase (Sales), Net | 140,000,000 | 200,000,000 | ||
Sale of Derivative Instruments Interest Rate Swap | 0 | 0 | ||
Interest Rate Swap [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Designated as Hedging Instrument [Member] | ||||
Derivative, Notional Amount, Purchase (Sales), Net | $ 140,000,000 | $ 200,000,000 |
Derivative Instruments and He_4
Derivative Instruments and Hedging Activities (Outstanding Derivative Instruments) (Details) | 12 Months Ended | |||
Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($)MMBTUMWh | Dec. 31, 2016USD ($) | Mar. 29, 2018USD ($) | |
Sale of Derivative Instruments Interest Rate Swap | $ (60,000,000) | |||
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Sale of Derivative Instruments Interest Rate Swap | $ (60,000,000) | |||
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 | |||
Sales of Units Derivative Instruments Forward Power Contracts Designated as Cash Flow Hedge | MWh | (1,667,000) | |||
Derivative, Nonmonetary Notional Amount MWh | MWh | (988,500) | |||
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 | 140,000,000 | 200,000,000 | ||
Derivative, Notional Amount, Purchase (Sales), Net | 140,000,000 | 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 | 140,000,000 | 200,000,000 | ||
Not Designated as Hedging Instrument [Member] | ||||
Derivative, Gain (Loss) on Derivative, Net | 900,000 | 3,200,000 | $ (900,000) | |
Not Designated as Hedging Instrument [Member] | Commodity Contract - FTR [Member] | ||||
Derivative, Gain (Loss) on Derivative, Net | 700,000 | $ 400,000 | (300,000) | |
Purchase of Units Derivative Instruments Financial Transmission Rights | MWh | 2,100 | |||
Sale of Units Derivative Instruments Financial Transmission Rights | MWh | 0 | |||
Derivative, Nonmonetary Notional Amount MWh | MWh | 2,100 | |||
Not Designated as Hedging Instrument [Member] | Natural Gas [Member] | ||||
Derivative, Gain (Loss) on Derivative, Net | 200,000 | $ 1,600,000 | 2,600,000 | |
Purchase of Units Derivative Instruments Natural Gas | MMBTU | 3,322,500 | |||
Sale of Units Derivative Instruments Natural Gas | MMBTU | (390,000) | |||
Derivative, Nonmonetary Notional Amount MWh | MMBTU | 2,932,500 | |||
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | ||||
Derivative, Gain (Loss) on Derivative, Net | $ 0 | $ 1,200,000 | $ (3,200,000) | |
Purchase of Units Derivative Instruments Forward Power Contracts Not Designated as Hedged | MWh | 871,000 | |||
Sales of Units Derivative Instruments Forward Power Contracts Not Designated as Hedged | MWh | (765,600) | |||
Derivative, Nonmonetary Notional Amount MWh | MWh | 105,400 |
Derivative Instruments and He_5
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, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Forward Contract Power [Member] | |||
Beginning accumulated derivative gain / (loss) in AOCI | $ (2.8) | $ (4.3) | $ 9.2 |
Net gains / (losses) associated with current period hedging transactions | 0 | 8.8 | 15.7 |
Ending accumulated derivative gain / (loss) in AOCI | 0.4 | (2.8) | (4.3) |
Portion expected to be reclassified to earnings in the next twelve months | $ 0 | ||
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) | 0 months | ||
Interest Rate Contract [Member] | |||
Beginning accumulated derivative gain / (loss) in AOCI | $ 17.5 | 17.4 | 17.5 |
Net gains / (losses) associated with current period hedging transactions | (0.1) | 0.8 | 0.4 |
Ending accumulated derivative gain / (loss) in AOCI | 16.6 | 17.5 | 17.4 |
Portion expected to be reclassified to earnings in the next twelve months | $ (0.8) | ||
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) | 20 months | ||
THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member] | |||
Derivative Instrument, loss from discontinued operations | (5.5) | (29.2) | |
Beginning accumulated derivative gain / (loss) in AOCI | $ 0 | (4.3) | 9.2 |
Net gains / (losses) associated with current period hedging transactions | 11.9 | 15.7 | |
Ending accumulated derivative gain / (loss) in AOCI | 0 | (4.3) | |
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 | 1.4 | 1.6 | 2 |
Net gains / (losses) associated with current period hedging transactions | (0.1) | 0.5 | 0.4 |
Ending accumulated derivative gain / (loss) in AOCI | 0.6 | 1.4 | 1.6 |
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) | 20 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 | (0.8) | (0.7) | (0.5) |
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) | (0.7) | (0.8) |
Discontinued Operations, Held-for-sale or Disposed of by Sale [Member] | Forward Contract Power [Member] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | 3.2 | (7.3) | (29.2) |
Discontinued Operations, Held-for-sale or Disposed of by Sale [Member] | Interest Rate Contract [Member] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | $ 0 | $ 0 | $ 0 |
Derivative Instruments and He_6
Derivative Instruments and Hedging Activities (Classification within the Condensed Consolidated Statements of Results of Operations or Balance Sheets of the Gains and Losses) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Not Designated as Hedging Instrument [Member] | |||
Change in unrealized gain / (loss) | $ 0.2 | $ 1.6 | $ 4.3 |
Realized gain / (loss) | 0.7 | 1.6 | (5.2) |
Derivative, Gain (Loss) on Derivative, Net | 0.9 | 3.2 | (0.9) |
Not Designated as Hedging Instrument [Member] | Commodity Contract - FTR [Member] | |||
Change in unrealized gain / (loss) | 0.3 | (0.4) | 0.3 |
Realized gain / (loss) | 0.4 | 0.8 | (0.6) |
Derivative, Gain (Loss) on Derivative, Net | 0.7 | 0.4 | (0.3) |
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | |||
Change in unrealized gain / (loss) | 0 | 1.9 | 4 |
Realized gain / (loss) | 0 | (0.7) | (7.2) |
Derivative, Gain (Loss) on Derivative, Net | 0 | 1.2 | (3.2) |
Not Designated as Hedging Instrument [Member] | Natural Gas [Member] | |||
Change in unrealized gain / (loss) | (0.1) | 0.1 | 0 |
Realized gain / (loss) | 0.3 | 1.5 | 2.6 |
Derivative, Gain (Loss) on Derivative, Net | 0.2 | 1.6 | 2.6 |
Not Designated as Hedging Instrument [Member] | Discontinued Operations, Held-for-sale or Disposed of by Sale [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0.9 | 3.2 | (0.9) |
Not Designated as Hedging Instrument [Member] | Discontinued Operations, Held-for-sale or Disposed of by Sale [Member] | Commodity Contract - FTR [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0.7 | 0.4 | (0.3) |
Not Designated as Hedging Instrument [Member] | Discontinued Operations, Held-for-sale or Disposed of by Sale [Member] | Forward Contract Power [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | 1.2 | (3.2) |
Not Designated as Hedging Instrument [Member] | Discontinued Operations, Held-for-sale or Disposed of by Sale [Member] | Natural Gas [Member] | |||
Derivative, Gain (Loss) on Derivative, Net | 0.2 | 1.6 | $ 2.6 |
Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Interest Rate Swap [Member] | |||
Derivative Liability, Fair Value, Gross Liability | $ 0.6 | $ 1.5 |
Derivative Instruments and He_7
Derivative Instruments and Hedging Activities (Fair Value and Balance Sheet Location (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Total Assets [Member] | ||
Derivative Asset, Fair Value | $ 1.5 | $ 12.5 |
Derivative, Collateral, Obligation to Return Securities | 0 | (8.7) |
Derivative, Collateral, Obligation to Return Cash | 0 | 0 |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 1.5 | 3.8 |
Total Liabilities [Member] | ||
Derivative Liability, Fair Value | 15.3 | |
Derivative, Collateral, Right to Reclaim Securities | (8.7) | |
Derivative, Collateral, Right to Reclaim Cash | (1.4) | |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 5.2 | |
Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Current assets of discontinued operations and held-for-sale businesses [Member] | ||
Derivative Asset, Fair Value | 4.9 | |
Derivative, Collateral, Obligation to Return Securities | (4.9) | |
Derivative, Collateral, Obligation to Return Cash | 0 | |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 0 | |
Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Prepayments and Current Assets [Member] | ||
Derivative Asset, Fair Value | 0.9 | |
Derivative, Collateral, Obligation to Return Securities | 0 | |
Derivative, Collateral, Obligation to Return Cash | 0 | |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 0.9 | |
Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Current liabilities of discontinued operations and held-for-sale businesses [Member] | ||
Derivative Liability, Fair Value | 9 | |
Derivative, Collateral, Right to Reclaim Securities | (4.9) | |
Derivative, Collateral, Right to Reclaim Cash | (1.4) | |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 2.7 | |
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Other Current Assets [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Derivative Asset, Fair Value | 0.9 | 0 |
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Other Noncurrent Assets [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Derivative Liability, Fair Value | 0.6 | 1.5 |
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Long-term Derivative Positions [Member] | Other Deferred Asset [Member] | ||
Derivative Asset, Fair Value | 0.6 | 1.5 |
Derivative, Collateral, Obligation to Return Securities | 0 | 0 |
Derivative, Collateral, Obligation to Return Cash | 0 | 0 |
Derivative Asset, Fair Value, Amount Offset Against Collateral | $ 0.6 | 1.5 |
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Current assets of discontinued operations and held-for-sale businesses [Member] | ||
Derivative Asset, Fair Value | 5.3 | |
Derivative, Collateral, Obligation to Return Securities | (3.7) | |
Derivative, Collateral, Obligation to Return Cash | 0 | |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 1.6 | |
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Current liabilities of discontinued operations and held-for-sale businesses [Member] | ||
Derivative Liability, Fair Value | 5.9 | |
Derivative, Collateral, Right to Reclaim Securities | (3.7) | |
Derivative, Collateral, Right to Reclaim Cash | 0 | |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 2.2 | |
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Non-current assets of discontinued operations and held-for-sale businesses [Member] | ||
Derivative Asset, Fair Value | 0.6 | |
Derivative, Collateral, Obligation to Return Securities | 0 | |
Derivative, Collateral, Obligation to Return Cash | 0 | |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 0.6 | |
Not Designated as Hedging Instrument [Member] | Commodity Contract - FTR [Member] | Short-term Derivative Positions [Member] | Current assets of discontinued operations and held-for-sale businesses [Member] | ||
Derivative Asset, Fair Value | 0.2 | |
Derivative, Collateral, Obligation to Return Securities | (0.1) | |
Derivative, Collateral, Obligation to Return Cash | 0 | |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 0.1 | |
Not Designated as Hedging Instrument [Member] | Commodity Contract - FTR [Member] | Short-term Derivative Positions [Member] | Current liabilities of discontinued operations and held-for-sale businesses [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] | Current liabilities of discontinued operations and held-for-sale businesses [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 |
Debt (Narrative) (Details)
Debt (Narrative) (Details) $ in Millions | 6 Months Ended | 9 Months Ended | 12 Months Ended | ||||||||||
Dec. 31, 2019 | Jun. 30, 2019 | Dec. 31, 2018USD ($)debt_covenantfiscal_quarter | Jul. 03, 2018 | Sep. 30, 2018debt_covenant | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018USD ($)debt_covenantfiscal_quarter | Dec. 31, 2017USD ($) | Apr. 30, 2018USD ($) | Mar. 30, 2018USD ($) | Jan. 03, 2018 | Aug. 03, 2015USD ($) | |
Debt Instrument [Line Items] | |||||||||||||
Current portion - long-term debt | $ 103.6 | $ 103.6 | |||||||||||
Unamortized adjustments to market value from purchase accounting | 1.9 | 1.9 | |||||||||||
Unamortized Deferred Financing Costs | (4.3) | (4.3) | $ (6.8) | ||||||||||
Current portion - long-term debt | 103.6 | $ 103.6 | 4.6 | ||||||||||
Debt Covenant, Leverage Ratio, Maximum | 0.67 | ||||||||||||
Debt Covenant, Interest Coverage Ratio, Minimum | 2.50 | 2.10 | |||||||||||
Interest Coverage Ratio | 2.61 | ||||||||||||
Leverage Ratio | 1.47 | ||||||||||||
Debt Covenant, Total Debt to Total Capitalization Ratio, Maximum | 0.65 | ||||||||||||
Long Term Indebtedness, Less than or Equal to | $ 750 | 750 | |||||||||||
Debt Instrument, Unamortized Discount (Premium), Net | 0.5 | 0.5 | 0.6 | ||||||||||
Total Long-term Debt At Subsidiary With Purchase Accounting Adjustments | 586.1 | 586.1 | 646.6 | ||||||||||
Long-term Debt, Excluding Current Maturities | 1,372.3 | 1,372.3 | 1,700.2 | ||||||||||
Long-term Debt, Maturities, Repayments of Principal in Year Two | 144.7 | $ 144.7 | |||||||||||
Debt Covenant, Debt to EBITDA Ratio, Maximum | 7.25 | ||||||||||||
Debt to EBITDA Ratio | 5.84 | ||||||||||||
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Current portion - long-term debt | 4.6 | $ 4.6 | |||||||||||
Unamortized Deferred Financing Costs | (9.8) | ||||||||||||
Current portion - long-term debt | 4.6 | $ 4.6 | 4.6 | ||||||||||
Debt Covenant, Interest Coverage Ratio, Minimum | 2.50 | ||||||||||||
Debt Covenant, Total Debt to Total Capitalization Ratio, Maximum | 0.65 | ||||||||||||
Long Term Indebtedness, Less than or Equal to | $ 750 | 750 | |||||||||||
Unamortized Deferred Financing Costs (Subsidiary) | (6.3) | (6.3) | (9.8) | ||||||||||
Debt Instrument, Unamortized Discount (Premium), Net | 1.4 | 1.4 | 2 | ||||||||||
Long-term Debt, Excluding Current Maturities | 581.5 | 581.5 | 642 | ||||||||||
Long-term Debt, Maturities, Repayments of Principal in Year Two | $ 144.7 | 144.7 | |||||||||||
Senior Unsecured Notes At6.80 Maturing On October2019 [Member] | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Long-term Debt, Gross | $ 200 | ||||||||||||
Make Whole Premium | $ 5.1 | ||||||||||||
Extinguishment of debt, amount | $ 101 | ||||||||||||
Debt instrument interest percentage | 6.75% | 6.75% | |||||||||||
Term Loan Maturing 2022 (DPL) [Member] | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Debt Instrument, Maturity Date Range, End | Aug. 24, 2022 | ||||||||||||
Long-term Debt, Gross | $ 436.1 | $ 436.1 | 440.6 | ||||||||||
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 | $ 436.1 | $ 436.1 | 440.6 | ||||||||||
Eurodollar rate Term Loan B [Member] | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Debt instrument interest percentage | 3.25% | 3.25% | 2.00% | ||||||||||
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% | 2.00% | ||||||||||
Base Rate Term Loan B [Member] | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Debt instrument interest percentage | 2.25% | 2.25% | 1.00% | ||||||||||
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% | 1.00% | ||||||||||
Revolving Credit Agreement and Standby Letters of Credit [Member] | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Number of financial covenants | debt_covenant | 2 | ||||||||||||
Revolving Credit Agreement and Standby Letters of Credit [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Number of financial covenants | debt_covenant | 2 | ||||||||||||
Number of prior quarters included in debt to EBITDA ratio | fiscal_quarter | 4 | 4 | |||||||||||
Debt Covenant, Interest Coverage Ratio, Minimum | 2.50 | ||||||||||||
Interest Coverage Ratio | 8.09 | ||||||||||||
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 | $ 17.7 | $ 17.7 | 17.8 | ||||||||||
Debt instrument interest percentage | 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 | $ 17.7 | $ 17.7 | 17.8 | ||||||||||
Debt instrument interest percentage | 4.20% | 4.20% | |||||||||||
Term Loan Maturing 2022 [Member] | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Early prepayment rate | 101.00% | ||||||||||||
Standard Repayment Rate | 100.00% | ||||||||||||
Term Loan Maturing 2022 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Early prepayment rate | 101.00% | ||||||||||||
Standard Repayment Rate | 100.00% | ||||||||||||
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 | $ 0 | $ 0 | 70 | ||||||||||
Extinguishment of debt, amount | $ 70 | ||||||||||||
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 | $ 99 | $ 99 | 200 | ||||||||||
Debt instrument interest percentage | 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 | 2 | |||||||||||
Debt Instrument, Debt Covenant, Debt to EBITDA Ratio, Number of Quarters | fiscal_quarter | 4 | 4 | |||||||||||
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 | $ 780 | 780 | ||||||||||
Debt instrument interest percentage | 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 | $ 15.6 | $ 15.6 | 15.6 | ||||||||||
Debt instrument interest percentage | 8.125% | 8.125% | |||||||||||
Variable Rate Notes Backed by Term Loan and First Mortgage Bonds [Member] | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Extinguishment of debt, amount | $ 60 | ||||||||||||
Variable Rate Notes Backed by Term Loan and First Mortgage Bonds [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Extinguishment of debt, amount | $ 60 | ||||||||||||
Debt Instrument, Face Amount | $ 200 | ||||||||||||
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 | $ 140 | $ 140 | 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] | |||||||||||||
Debt Instrument, Maturity Date Range, End | Aug. 1, 2020 | ||||||||||||
Long-term Debt, Gross | 140 | $ 140 | 200 | ||||||||||
Subsequent Event [Member] | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Debt Covenant, Interest Coverage Ratio, Minimum | 2.25 | ||||||||||||
Debt Covenant, Debt to EBITDA Ratio, Maximum | 6.75 | 7 | 6.50 | ||||||||||
Debt [Member] | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Long-term Debt and Capital Lease Obligations, Including Current Maturities | 1,475.9 | 1,475.9 | 1,704.8 | ||||||||||
Debt [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Long-term Debt and Capital Lease Obligations, Including Current Maturities | $ 586.1 | $ 586.1 | $ 646.6 |
Debt (Long-term Debt) (Details)
Debt (Long-term Debt) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Oct. 01, 2017 | |
Debt Instrument [Line Items] | |||
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months | $ 103.6 | ||
Disposal Group, Including Discontinued Operations, Long-Term Debt | 0 | $ (0.3) | |
Unamortized Deferred Financing Costs | (4.3) | (6.8) | |
Debt Instrument, Unamortized Discount (Premium), Net | (0.5) | (0.6) | |
Total long-term debt at subsidary | 586.1 | 646.6 | |
Less: current portion | (103.6) | (4.6) | |
Long-term debt, net of current portion | $ 1,372.3 | 1,700.2 | |
Debt maturity date, earliest | 2,019 | ||
Debt maturity date, latest | 2,061 | ||
Long-term Debt, Maturities, Repayments of Principal in Year Two | $ 144.7 | ||
Long-term Debt, Maturities, Repayments of Principal in Year Three | 784.7 | ||
Long-term Debt, Maturities, Repayments of Principal in Year Four | 422.8 | ||
Long-term Debt, Maturities, Repayments of Principal in Year Five | 0.2 | ||
Long-term Debt, Maturities, Repayments of Principal after Year Five | 32.4 | ||
Total Maturities Before Unamortized Adjustments | 1,488.4 | ||
Unamortized adjustments to market value from purchase accounting | 1.9 | ||
Unamortized Deferred Financing Costs, Consolidated | (10.6) | ||
Long Term Debt Maturities Repayments Of Principal, Total | 1,475.9 | ||
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months | 4.6 | ||
Unamortized Deferred Financing Costs | (9.8) | ||
Unamortized Deferred Financing Costs (Subsidiary) | (6.3) | (9.8) | |
Debt Instrument, Unamortized Discount | (1.4) | (2) | |
Debt Instrument, Unamortized Discount (Premium), Net | (1.4) | (2) | |
Less: current portion | (4.6) | (4.6) | |
Long-term debt, net of current portion | 581.5 | 642 | |
Long-term Debt, Maturities, Repayments of Principal in Year Two | 144.7 | ||
Long-term Debt, Maturities, Repayments of Principal in Year Three | 4.7 | ||
Long-term Debt, Maturities, Repayments of Principal in Year Four | 422.8 | ||
Long-term Debt, Maturities, Repayments of Principal in Year Five | 0.2 | ||
Long-term Debt, Maturities, Repayments of Principal after Year Five | 16.8 | ||
Total Maturities Before Unamortized Adjustments | 593.8 | ||
Unamortized Deferred Financing Costs, Consolidated | (6.3) | ||
Long Term Debt Maturities Repayments Of Principal, Total | 586.1 | ||
Term Loan Maturing 2022 (DPL) [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Gross | $ 436.1 | 440.6 | |
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 | $ 436.1 | 440.6 | |
Debt instrument maturity year | Aug. 24, 2022 | ||
Tax-exempt First Mortgage Bonds - rates from: 2.49% - 2.93% (a) and 1.29% - 1.42% (b) | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Gross | $ 140 | 200 | |
Debt instrument maturity year | Aug. 1, 2020 | ||
Tax-exempt First Mortgage Bonds - rates from: 2.49% - 2.93% (a) and 1.29% - 1.42% (b) | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Gross | $ 140 | 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 | $ 17.7 | 17.8 | |
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 | $ 17.7 | 17.8 | |
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 | $ 0 | 70 | |
Bank Term Loan maturing in May 2018 [Member] | |||
Debt Instrument [Line Items] | |||
Debt instrument maturity year | Jul. 31, 2020 | ||
Five Year Senior Unsecured Notes At6.75 Maturing October152019 [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Gross | $ 99 | 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) | 3.57% | 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) | 3.57% | 4.00% | |
Minimum [Member] | Tax-exempt First Mortgage Bonds - rates from: 2.49% - 2.93% (a) and 1.29% - 1.42% (b) | |||
Debt Instrument [Line Items] | |||
Debt instrument interest percentage | 2.49% | 1.29% | |
Minimum [Member] | Tax-exempt First Mortgage Bonds - rates from: 2.49% - 2.93% (a) and 1.29% - 1.42% (b) | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Debt Instrument [Line Items] | |||
Debt instrument interest percentage | 2.49% | ||
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) | 4.82% | 4.60% | |
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) | 4.82% | 4.60% | |
Maximum [Member] | Tax-exempt First Mortgage Bonds - rates from: 2.49% - 2.93% (a) and 1.29% - 1.42% (b) | |||
Debt Instrument [Line Items] | |||
Debt instrument interest percentage | 2.93% | 1.42% | |
Maximum [Member] | Tax-exempt First Mortgage Bonds - rates from: 2.49% - 2.93% (a) and 1.29% - 1.42% (b) | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Debt Instrument [Line Items] | |||
Debt instrument interest percentage | 2.93% | ||
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 | $ 1,475.9 | $ 1,704.8 | |
Debt [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt and Capital Lease Obligations, Including Current Maturities | $ 586.1 | $ 646.6 | |
Generation [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Debt Instrument [Line Items] | |||
Disposal Group, Including Discontinued Operations, Long-Term Debt | $ (0.3) |
Debt (Long-term Debt Maturities
Debt (Long-term Debt Maturities) (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 | Oct. 01, 2017 |
Debt Instrument [Line Items] | |||
Unamortized Deferred Financing Costs, Consolidated | $ (10.6) | ||
Current portion - long-term debt | 103.6 | ||
Long-term Debt, Maturities, Repayments of Principal in Year Two | 144.7 | ||
2,018 | 784.7 | ||
2,019 | 422.8 | ||
2,020 | 0.2 | ||
Thereafter | 32.4 | ||
Total Maturities | 1,488.4 | ||
Total long-term debt | 1,475.9 | ||
Disposal Group, Including Discontinued Operations, Long-Term Debt | 0 | $ 0.3 | |
Unamortized Deferred Financing Costs | (4.3) | (6.8) | |
Current portion - long-term debt | 103.6 | 4.6 | |
Long-term Debt, Excluding Current Maturities | 1,372.3 | 1,700.2 | |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Debt Instrument [Line Items] | |||
Unamortized Deferred Financing Costs, Consolidated | (6.3) | ||
Current portion - long-term debt | 4.6 | ||
Long-term Debt, Maturities, Repayments of Principal in Year Two | 144.7 | ||
2,018 | 4.7 | ||
2,019 | 422.8 | ||
2,020 | 0.2 | ||
Thereafter | 16.8 | ||
Total Maturities | 593.8 | ||
Debt Instrument, Unamortized Discount | (1.4) | (2) | |
Total long-term debt | 586.1 | ||
Unamortized Deferred Financing Costs | (9.8) | ||
Current portion - long-term debt | 4.6 | 4.6 | |
Long-term Debt, Excluding Current Maturities | 581.5 | 642 | |
Unamortized Deferred Financing Costs (Subsidiary) | (6.3) | (9.8) | |
Term Loan Maturing 2022 (DPL) [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Gross | 436.1 | 440.6 | |
Term Loan Maturing 2022 (DPL) [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Gross | 436.1 | 440.6 | |
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 | 140 | 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 | 140 | 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 | 17.7 | 17.8 | |
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 | 17.7 | 17.8 | |
Generation [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Debt Instrument [Line Items] | |||
Disposal Group, Including Discontinued Operations, Long-Term Debt | $ 0.3 | ||
Debt [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt and Capital Lease Obligations, Including Current Maturities | 1,475.9 | 1,704.8 | |
Debt [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt and Capital Lease Obligations, Including Current Maturities | $ 586.1 | $ 646.6 |
Income Taxes (Components of Inc
Income Taxes (Components of Income Tax Expense) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Taxes [Line Items] | |||||
Tax Cuts and Jobs Act of 2017, change in income tax expense (benefit) | $ 15.5 | $ 13.7 | |||
Change in deferred tax regulatory asset/liability due to TCJA | 17 | 135.2 | $ 17 | $ 135.2 | |
Estimated Annual Effective Income Tax Rate, Continuing Operations | 21.00% | 35.00% | |||
Federal income tax | $ 6.7 | $ (2.3) | $ 4.3 | ||
State income taxes, net of federal effect | 0.1 | 0.1 | 0 | ||
Depreciation of AFUDC - Equity | (4.6) | 1.1 | 3.3 | ||
Investment tax credit amortized | (0.3) | (0.3) | (0.4) | ||
Effective income tax rate reconciliation, accrual for open tax years | 0 | (0.4) | 2 | ||
Accrual (settlement) for open tax years | 0 | (0.7) | (9.3) | ||
Other, net | (1.2) | (2.5) | (2.3) | ||
Tax expense / (benefit) | 0.7 | (5) | (2.4) | ||
Federal - Current | (17.9) | 23.8 | (3.3) | ||
State and Local - Current | 0.5 | 0.2 | 0 | ||
Total Current | (17.4) | 24 | (3.3) | ||
Federal - Deferred | 18.3 | (28.8) | 0.8 | ||
State and Local - Deferred | (0.2) | (0.2) | 0.1 | ||
Total Deferred | $ 18.1 | (29) | 0.9 | ||
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense | 3.5 | (0.9) | |||
Tax rate before change due to Tax Cuts and Jobs Act of 2017 | 35.00% | ||||
Tax rate after Tax Cuts and Jobs Act of 2017 | 21.00% | ||||
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Income Taxes [Line Items] | |||||
Change in deferred tax regulatory asset/liability due to TCJA | 17 | 135.2 | $ 17 | $ 135.2 | |
Estimated Annual Effective Income Tax Rate, Continuing Operations | 21.00% | 35.00% | |||
Federal income tax | $ 22.2 | $ 31 | 50.1 | ||
State income taxes, net of federal effect | 0.6 | 0.4 | 0.4 | ||
Depreciation of AFUDC - Equity | (4.3) | 1.2 | 3 | ||
Investment tax credit amortized | (0.3) | (0.3) | (0.4) | ||
Effective income tax rate reconciliation, accrual for open tax years | 0 | (0.5) | 3.4 | ||
Other, net | (0.5) | (0.7) | (10.5) | ||
Tax expense / (benefit) | 17.7 | 31.1 | 46 | ||
Federal - Current | 1.4 | 13.5 | 37.7 | ||
State and Local - Current | 0 | 0.2 | 0.5 | ||
Total Current | 1.4 | 13.7 | 38.2 | ||
Federal - Deferred | 15.5 | 17 | 7.7 | ||
State and Local - Deferred | 0.8 | 0.4 | 0.1 | ||
Total Deferred | $ 16.3 | 17.4 | 7.8 | ||
Increase (Decrease) in Income Taxes | $ (0.7) | $ 0.4 | |||
Tax rate before change due to Tax Cuts and Jobs Act of 2017 | 35.00% | ||||
Tax rate after Tax Cuts and Jobs Act of 2017 | 21.00% | ||||
Continuing Operations [Member] | |||||
Income Taxes [Line Items] | |||||
Tax Cuts and Jobs Act of 2017, change in income tax expense (benefit) | $ (1.2) | $ (0.4) |
Income Taxes (Effective and Sta
Income Taxes (Effective and Statutory Rate Reconciliation) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Entity Information [Line Items] | |||
Non-cash capital contribution | $ 40 | $ 97.1 | $ 0 |
Estimated Annual Effective Income Tax Rate, Continuing Operations | 21.00% | 35.00% | |
Statutory Federal tax rate | 21.00% | 35.00% | 35.00% |
State taxes, net of Federal tax benefit | 0.40% | (1.50%) | 0.20% |
Depreciation of flow-through differences | (0.10%) | 4.90% | (5.00%) |
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Depreciation and Amortization, Percent | (14.60%) | (17.60%) | 26.70% |
Effective Income Tax Rate Reconciliation, Tax Credit, Percent | (1.00%) | 5.10% | (3.30%) |
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Percent | 0.00% | 11.00% | (75.10%) |
Effective Income Tax Rate Reconciliation, Permanent Difference, Percent | 0.00% | 4.80% | 2.80% |
Other, net | (3.50%) | 35.20% | (0.70%) |
Effective tax rate | 2.20% | 76.90% | (19.40%) |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Entity Information [Line Items] | |||
Estimated Annual Effective Income Tax Rate, Continuing Operations | 21.00% | 35.00% | |
Statutory Federal tax rate | 21.00% | 35.00% | 35.00% |
State taxes, net of Federal tax benefit | 0.60% | 0.40% | 0.30% |
Depreciation of flow-through differences | (0.10%) | 1.40% | 2.10% |
Effective Income Tax Rate Reconciliation, Tax Credit, Investment, Percent | (0.30%) | (0.40%) | (0.30%) |
Effective Income Tax Rate Reconciliation, Depreciation of flow-through years | (4.00%) | 0.00% | 0.00% |
Other, net | (0.20%) | (1.30%) | (5.10%) |
Effective tax rate | 17.00% | 35.10% | 32.00% |
Income Taxes (Components of Def
Income Taxes (Components of Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Taxes [Line Items] | |||
Effective Income Tax Rate Reconciliation, deferred tax adjustment percent | 0.00% | 11.00% | (75.10%) |
Depreciation / property basis | $ (112) | $ (113.4) | |
Income taxes recoverable | 25 | 11 | |
Deferred Tax Liabilities, Regulatory Assets and Liabilities | (15.4) | (23.1) | |
Investment tax credit | 0.5 | 0.7 | |
Compensation and employee benefits | 1.4 | 19 | |
Intangibles | (0.3) | (0.4) | |
Long-term debt | (2.1) | (0.2) | |
Other | (13.2) | (7.1) | |
Net non-current liabilities | $ (116.1) | $ (113.5) | |
Estimated Annual Effective Income Tax Rate, Continuing Operations | 21.00% | 35.00% | |
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense | $ 3.5 | $ (0.9) | |
Deferred tax assets related to state and local tax net operating loss carryforwards, net of related valuation allowances | $ 10.9 | 9.3 | |
Deferred tax assets related to state and local net operating loss carryforwards, valuation allowances | 10.9 | 9.3 | |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Income Taxes [Line Items] | |||
Depreciation / property basis | (130.6) | (126.5) | |
Income taxes recoverable | 25 | 11 | |
Deferred Tax Liabilities, Regulatory Assets and Liabilities | (16.2) | (23.9) | |
Investment tax credit | 0.5 | 0.4 | |
Compensation and employee benefits | 0.3 | 17.6 | |
Other | (10.7) | (9.6) | |
Net non-current liabilities | $ (131.7) | $ (131) | |
Estimated Annual Effective Income Tax Rate, Continuing Operations | 21.00% | 35.00% | |
Increase (Decrease) in Income Taxes | $ (0.7) | $ 0.4 |
Income Taxes (Tax or Benefit cr
Income Taxes (Tax or Benefit credited to AOCI) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Taxes [Line Items] | |||
Tax expense/ (benefit) | $ 0.2 | $ 0.2 | $ (9.6) |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Income Taxes [Line Items] | |||
Tax expense/ (benefit) | $ (0.3) | $ 4 | $ (7) |
Income Taxes (Reconciliation of
Income Taxes (Reconciliation of Unrecognized Tax Benefits) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | ||
Balance at beginning of year | $ 3.5 | $ 3.7 |
Tax positions taken during prior periods | 0 | 0 |
Lapse of applicable statute of limitations | 0 | (0.2) |
Balance at end of year | 3.5 | 3.5 |
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 | 4.8 | 4.9 |
Tax positions taken during prior periods | 0 | 0 |
Lapse of applicable statute of limitations | 0 | (0.1) |
Balance at end of year | $ 4.8 | $ 4.8 |
Income Taxes (Narrative) (Detai
Income Taxes (Narrative) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Taxes [Line Items] | |||||
Tax Cuts and Jobs Act of 2017, change in income tax expense (benefit) | $ 15.5 | $ 13.7 | |||
Tax rate before change due to Tax Cuts and Jobs Act of 2017 | 35.00% | ||||
Tax rate after Tax Cuts and Jobs Act of 2017 | 21.00% | ||||
Non-cash capital contribution | $ 40 | $ 97.1 | $ 0 | ||
Change in deferred tax regulatory asset/liability due to TCJA | 17 | 135.2 | 17 | 135.2 | |
Unrecognized tax benefits due to uncertainty in timing of deductibility | $ 3.5 | ||||
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% | ||||
Tax rate after Tax Cuts and Jobs Act of 2017 | 21.00% | ||||
Change in deferred tax regulatory asset/liability due to TCJA | $ 17 | $ 135.2 | $ 17 | $ 135.2 | |
Unrecognized tax benefits due to uncertainty in timing of deductibility | $ 4.8 |
Benefit Plans (Narrative) (Deta
Benefit Plans (Narrative) (Details) - USD ($) | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Defined Benefit Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Amount Billed to Service Company | $ 1,800,000 | $ 1,100,000 | ||
Defined contribution plan, maximum annual contributions per employee (percent) | 85.00% | |||
Employer contributions to defined contribution plan | $ 3,700,000 | 3,100,000 | $ 5,100,000 | |
Accumulated benefit obligation for our defined benefit pension plans | 378,700,000 | 428,300,000 | ||
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Amount Billed to Service Company | $ 1,800,000 | 1,100,000 | ||
Defined contribution plan, maximum annual contributions per employee (percent) | 85.00% | |||
Employer contributions to defined contribution plan | $ 3,700,000 | 3,100,000 | 5,100,000 | |
Accumulated benefit obligation for our defined benefit pension plans | 378,700,000 | 428,300,000 | ||
Defined Benefit Plan, Amount Billed to AES Ohio Generation | $ 3,300,000 | 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] | ||||
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss) | $ (34,600,000) | 28,100,000 | ||
Payment for Pension Benefits | $ 7,500,000 | $ 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 | 6.25% | 6.50% | 6.50% | |
Discount rate for obligations | 4.35% | 3.66% | 4.28% | |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 3.66% | 4.28% | 4.49% | |
Defined Benefit Plan, Plan Assets, Amount | $ 312,900,000 | $ 357,500,000 | $ 341,000,000 | |
Service cost | 6,100,000 | 5,700,000 | 5,700,000 | |
Interest cost | 13,800,000 | 14,200,000 | 14,700,000 | |
Defined Benefit Plan, Funded (Unfunded) Status of Plan | $ (73,600,000) | (79,400,000) | ||
Defined benefit plan, amortization period for underfunding excess | 7 years | |||
Pension [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss) | $ (34,600,000) | 28,100,000 | ||
Payment for Pension Benefits | $ 7,500,000 | $ 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 | 6.25% | 6.50% | 6.50% | |
Discount rate for obligations | 4.35% | 3.66% | 4.28% | |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 3.66% | 4.28% | 4.49% | |
Defined Benefit Plan, Plan Assets, Amount | $ 312,900,000 | $ 357,500,000 | $ 341,000,000 | |
Service cost | 6,100,000 | 5,700,000 | 5,700,000 | |
Interest cost | 13,800,000 | 14,200,000 | $ 14,700,000 | |
Defined Benefit Plan, Funded (Unfunded) Status of Plan | $ (73,600,000) | (79,400,000) | ||
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 | $ 9,200,000 | 12,700,000 | ||
Postretirement [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Funded (Unfunded) Status of Plan | $ 9,200,000 | $ 12,700,000 | ||
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 | $ 3,200,000 | |||
Decrease in pension cost due to change in return on assets | (3,200,000) | |||
Decrease in pension cost due to change in discount rate | (100,000) | |||
Increase in pension cost due to change in discount rate | 400,000 | |||
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 | 3,200,000 | |||
Decrease in pension cost due to change in return on assets | (3,200,000) | |||
Decrease in pension cost due to change in discount rate | (100,000) | |||
Increase in pension cost due to change in discount rate | 400,000 | |||
Scenario, Forecast [Member] | Pension [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Service cost | 5,400,000 | |||
Defined Benefit Plan, Plan Assets, Administration Expense | 1,900,000 | |||
Scenario, Forecast [Member] | Pension [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Service cost | 5,400,000 | |||
Defined Benefit Plan, Plan Assets, Administration Expense | $ 1,900,000 | |||
Scenario, Forecast [Member] | SERP [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Target Allocation Percentage | 101.00% | |||
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 | 101.00% | |||
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 | $ 2,400 | |||
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 | $ 2,400 | |||
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, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Noncurrent liabilities | $ (82.3) | $ (90.3) | |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Noncurrent liabilities | (83.2) | (91.1) | |
Postretirement [Member] | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Defined Benefit Plan, Funded (Unfunded) Status of Plan | 9.2 | 12.7 | |
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 | 9.2 | 12.7 | |
Pension [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement and Curtailment | 0 | (4.1) | $ (3.8) |
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | |||
Benefit obligation at January 1 | 436.9 | 419.6 | |
Service cost | 6.1 | 5.7 | 5.7 |
Interest cost | 13.8 | 14.2 | 14.7 |
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment | 5.1 | 0 | |
Defined Benefit Plan, Benefit Obligation, (Increase) Decrease for Curtailment | 0 | 3 | |
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss) | (34.6) | 28.1 | |
Benefit obligation at December 31 | 386.5 | 436.9 | 419.6 |
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value of plan assets at January 1 | 357.5 | 341 | |
Actual return / (loss) on plan assets | (11.7) | 44.8 | |
Contributions to plan assets | 7.9 | 5.4 | |
Fair value of plan assets at December 31 | 312.9 | 357.5 | 341 |
Defined Benefit Plan, Funded (Unfunded) Status of Plan | (73.6) | (79.4) | |
Current liabilities | (0.4) | (0.4) | |
Noncurrent liabilities | (73.2) | (79) | |
Net asset / (liability) at December 31 | (73.6) | (79.4) | |
Prior service cost | 9.1 | 4.9 | |
Net actuarial loss | 103.3 | 111.4 | |
Accumulated other comprehensive income, regulatory assets and regulatory liabilities, pre-tax | 112.4 | 116.3 | |
Defined Benefit Plan, Plan Assets, Benefits Paid | 40.8 | 33.7 | |
Defined Benefit Plan, Benefit Obligation, Benefits Paid | 40.8 | 33.7 | |
Pension [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement and Curtailment | 0 | (5.6) | (5.7) |
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | |||
Benefit obligation at January 1 | 436.9 | 419.6 | |
Service cost | 6.1 | 5.7 | 5.7 |
Interest cost | 13.8 | 14.2 | 14.7 |
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment | 5.1 | 0 | |
Defined Benefit Plan, Benefit Obligation, (Increase) Decrease for Curtailment | 0 | 3 | |
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss) | (34.6) | 28.1 | |
Benefit obligation at December 31 | 386.5 | 436.9 | 419.6 |
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value of plan assets at January 1 | 357.5 | 341 | |
Actual return / (loss) on plan assets | (11.7) | 44.8 | |
Contributions to plan assets | 7.9 | 5.4 | |
Fair value of plan assets at December 31 | 312.9 | 357.5 | $ 341 |
Defined Benefit Plan, Funded (Unfunded) Status of Plan | (73.6) | (79.4) | |
Current liabilities | (0.4) | (0.4) | |
Noncurrent liabilities | (73.2) | (79) | |
Net asset / (liability) at December 31 | (73.6) | (79.4) | |
Prior service cost | 10.4 | 6.7 | |
Net actuarial loss | 137.2 | 148.3 | |
Accumulated other comprehensive income, regulatory assets and regulatory liabilities, pre-tax | 147.6 | 155 | |
Defined Benefit Plan, Plan Assets, Benefits Paid | 40.8 | 33.7 | |
Defined Benefit Plan, Benefit Obligation, Benefits Paid | 40.8 | 33.7 | |
Regulatory Asset [Member] | Pension [Member] | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Accumulated other comprehensive income, regulatory assets and regulatory liabilities, pre-tax | 87.2 | 92.1 | |
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 | 87.3 | 92.2 | |
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 | 25.2 | 24.2 | |
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 | $ 60.3 | $ 62.8 |
Benefit Plans (Net Periodic Ben
Benefit Plans (Net Periodic Benefit Cost (Income)) (Details) - Pension [Member] - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Service cost | $ 6.1 | $ 5.7 | $ 5.7 |
Interest cost | 13.8 | 14.2 | 14.7 |
Expected return on assets | (21.2) | (22.8) | (22.8) |
Defined Benefit Plan, Curtailments | 0 | 4.1 | 3.8 |
Actuarial gain / (loss) | 6.4 | 5.3 | 4.3 |
Prior service cost | 0.9 | 1.1 | 1.8 |
Net Periodic benefit cost / (income) before adjustments | $ 6 | $ 7.6 | $ 7.5 |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 3.66% | 4.28% | 4.49% |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets | 6.25% | 6.50% | 6.50% |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Service cost | $ 6.1 | $ 5.7 | $ 5.7 |
Interest cost | 13.8 | 14.2 | 14.7 |
Expected return on assets | (21.2) | (22.8) | (22.8) |
Defined Benefit Plan, Curtailments | 0 | 5.6 | 5.7 |
Actuarial gain / (loss) | 9.4 | 8.7 | 7.2 |
Prior service cost | 1.4 | 1.5 | 3 |
Net Periodic benefit cost / (income) before adjustments | $ 9.5 | $ 12.9 | $ 13.5 |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 3.66% | 4.28% | 4.49% |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets | 6.25% | 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 | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Defined Benefit Plan Disclosure [Line Items] | |||
Net actuarial (gain) / loss | $ 3.4 | $ 9.1 | $ 20.9 |
Defined Benefit Plan, Accumulated Other Comprehensive Income, Plan Curtailments | 0 | (4.1) | (3.8) |
Reversal of amortization item, Net actuarial (gain) / loss | (6.4) | (5.3) | (4.3) |
Reversal of amortization item, Prior service cost / (credit) | (0.9) | (1.1) | (1.8) |
Total recognized in Accumulated other comprehensive income, Regulatory assets and Regulatory liabilities | (3.9) | (1.4) | 11 |
Total recognized in net periodic benefit cost and Accumulated other comprehensive income, Regulatory assets and Regulatory liabilities | 2.1 | 6.2 | 18.5 |
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement and Curtailment | 0 | (4.1) | (3.8) |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Net actuarial (gain) / loss | 3.4 | 9.1 | 20.9 |
Defined Benefit Plan, Accumulated Other Comprehensive Income, Plan Curtailments | 0 | (5.6) | (5.7) |
Reversal of amortization item, Net actuarial (gain) / loss | (9.4) | (8.7) | (7.2) |
Reversal of amortization item, Prior service cost / (credit) | (1.4) | (1.5) | (3) |
Total recognized in Accumulated other comprehensive income, Regulatory assets and Regulatory liabilities | (7.4) | (6.7) | 5 |
Total recognized in net periodic benefit cost and Accumulated other comprehensive income, Regulatory assets and Regulatory liabilities | 2.1 | 6.2 | 18.5 |
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement and Curtailment | $ 0 | $ (5.6) | $ (5.7) |
Benefit Plans (Weighted Average
Benefit Plans (Weighted Average Assumptions Used to Determine Benefit Obligations) (Details) - Pension [Member] | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Defined Benefit Plan Disclosure [Line Items] | |||
Discount rate for obligations | 4.35% | 3.66% | 4.28% |
Rate of compensation increases | 3.94% | 3.94% | 3.94% |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount rate for obligations | 4.35% | 3.66% | 4.28% |
Rate of compensation increases | 3.94% | 3.94% | 3.94% |
Benefit Plans (Weighted Avera_2
Benefit Plans (Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost (Income)) (Details) - Pension [Member] | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 3.66% | 4.28% | 4.49% |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets | 6.25% | 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 | 3.66% | 4.28% | 4.49% |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets | 6.25% | 6.50% | 6.50% |
Benefit Plans (Defined Benefits
Benefit Plans (Defined Benefits Plan Assets, Target Allocations) (Details) | Dec. 31, 2018 | Dec. 31, 2017 |
Equity Securities [Member] | ||
Target Allocation | 38.00% | |
Percentage of plan assets | 33.00% | 35.00% |
Debt Securities [Member] | ||
Target Allocation | 56.00% | |
Percentage of plan assets | 58.00% | 55.00% |
Cash and Cash Equivalents [Member] | ||
Target Allocation | 0.00% | |
Percentage of plan assets | 1.00% | 0.00% |
Real Estate [Member] | ||
Target Allocation | 6.00% | |
Percentage of plan assets | 8.00% | 10.00% |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Equity Securities [Member] | ||
Target Allocation | 38.00% | |
Percentage of plan assets | 33.00% | 35.00% |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Debt Securities [Member] | ||
Target Allocation | 56.00% | |
Percentage of plan assets | 58.00% | 55.00% |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Cash and Cash Equivalents [Member] | ||
Target Allocation | 0.00% | |
Percentage of plan assets | 1.00% | 0.00% |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Real Estate [Member] | ||
Target Allocation | 6.00% | |
Percentage of plan assets | 8.00% | 10.00% |
Benefit Plans (Fair Value Measu
Benefit Plans (Fair Value Measurements for Pension Plan Assets) (Details) - Pension [Member] - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Defined Benefit Plan Disclosure [Line Items] | |||
Total Pension Plan Assets | $ 312.9 | $ 357.5 | $ 341 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Pension Plan Assets | 312.9 | 357.5 | $ 341 |
Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Pension Plan Assets | 288.8 | 321.3 | |
Fair Value, Inputs, Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Pension Plan Assets | 288.8 | 321.3 | |
Fair Value, Inputs, Level 2 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Pension Plan Assets | 24.1 | 36.2 | |
Fair Value, Inputs, Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Pension Plan Assets | 24.1 | 36.2 | |
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 | 79.3 | 78.2 | |
U.S. Equities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 79.3 | 78.2 | |
U.S. Equities [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 79.3 | 78.2 | |
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 | 79.3 | 78.2 | |
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 | 25.9 | 46.3 | |
International Equities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 25.9 | 46.3 | |
International Equities [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 25.9 | 46.3 | |
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 | 25.9 | 46.3 | |
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 | 143.7 | 163.3 | |
Fixed Income Funds [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 143.7 | 163.3 | |
Fixed Income Funds [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Equity Securities | 143.7 | 163.3 | |
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 | 143.7 | 163.3 | |
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 | 37.5 | 33.5 | |
US Treasury Securities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Debt Securities | 37.5 | 33.5 | |
US Treasury Securities [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Debt Securities | 37.5 | 33.5 | |
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 | 37.5 | 33.5 | |
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 | |
Money Market Funds [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Debt Securities | 2.4 | ||
Money Market Funds [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Debt Securities | 2.4 | ||
Money Market Funds [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Debt Securities | 2.4 | ||
Money Market Funds [Member] | Fair Value, Inputs, Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Debt Securities | 2.4 | ||
Money Market Funds [Member] | Fair Value, Inputs, Level 2 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Debt Securities | 0 | ||
Money Market Funds [Member] | Fair Value, Inputs, Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Debt Securities | 0 | ||
Money Market Funds [Member] | Fair Value, Inputs, Level 3 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Debt Securities | 0 | ||
Money Market Funds [Member] | Fair Value, Inputs, Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Debt Securities | 0 | ||
Core Property Collective Fund [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Other Investments | 24.1 | 36.2 | |
Core Property Collective Fund [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Other Investments | 24.1 | 36.2 | |
Core Property Collective Fund [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Other Investments | 0 | 0 | |
Core Property Collective Fund [Member] | Fair Value, Inputs, Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Other Investments | 0 | 0 | |
Core Property Collective Fund [Member] | Fair Value, Inputs, Level 2 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Other Investments | 24.1 | 36.2 | |
Core Property Collective Fund [Member] | Fair Value, Inputs, Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Other Investments | 24.1 | 36.2 | |
Core Property Collective Fund [Member] | Fair Value, Inputs, Level 3 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Other Investments | 0 | 0 | |
Core Property Collective Fund [Member] | Fair Value, Inputs, Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total Other Investments | $ 0 | $ 0 |
Benefit Plans (Estimated Future
Benefit Plans (Estimated Future Benefit Payments and Medicare Part D Reimbursements) (Details) - Pension [Member] $ in Millions | Dec. 31, 2018USD ($) |
2,016 | $ 26.7 |
2,017 | 26.5 |
2,018 | 26.3 |
2,019 | 26 |
2,020 | 25.9 |
2021 - 2025 | 125.1 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |
2,016 | 26.7 |
2,017 | 26.5 |
2,018 | 26.3 |
2,019 | 26 |
2,020 | 25.9 |
2021 - 2025 | $ 125.1 |
Equity (Narrative) (Details)
Equity (Narrative) (Details) $ / shares in Units, $ in Millions | 12 Months Ended | ||||
Dec. 31, 2018USD ($)$ / sharesshares | Dec. 31, 2017USD ($)shares | Dec. 31, 2016USD ($) | 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) | $ (2,844.4) | $ (2,915.5) | |||
Common stock, shares authorized | shares | 1,500 | 1,500 | |||
Common stock, shares outstanding | shares | 1 | 1 | |||
Leverage Ratio | 1.47 | ||||
Accounts Payable, Related Parties, Current | $ 4.8 | $ 3.9 | |||
Non-cash capital contribution | 40 | 97.1 | $ 0 | ||
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Class of Stock [Line Items] | |||||
Retained earnings / (deficit) | $ (231.6) | $ (319.3) | |||
Common stock, shares authorized | shares | 50,000,000 | 50,000,000 | |||
Common stock, shares outstanding | shares | 41,172,173 | 41,172,173 | |||
Accounts Payable, Related Parties, Current | $ 4.8 | $ 3.9 | |||
Proceeds from Contributions from Parent | 80 | 70 | 0 | ||
Dividends, Common Stock, Cash | 43.8 | (39) | 70 | ||
Payments of Ordinary Dividends, Common Stock | $ 43.8 | 39 | 70 | ||
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 | 0 | 7.5 | ||
Other Paid-In Capital [Member] | |||||
Class of Stock [Line Items] | |||||
Non-cash capital contribution | 40 | 97.1 | |||
Other Paid-In Capital [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Class of Stock [Line Items] | |||||
Proceeds from Contributions from Parent | (80) | (70) | |||
Dividends, Common Stock, Cash | 43.8 | $ 39 | |||
Generation [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||||
Class of Stock [Line Items] | |||||
Disposal Group, Including Discontinued Operation, Net Assets | $ 10 | $ 0 | $ 86.2 |
Equity (Preferred Shares Outsta
Equity (Preferred Shares Outstanding) (Details) | Dec. 31, 2018$ / 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, Comm_3
Contractual Obligations, Commercial Commitments and Contingencies (Narative) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Public Utility, Property, Plant and Equipment [Line Items] | ||
Due to third parties, current | $ 0.9 | |
DPLE [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Third party guarantees | $ 23.6 | |
Debt Obligation on 4.9% Equity Ownership [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Equity ownership interest | 4.90% | |
Equity ownership interest aggregate cost | $ 68.1 | |
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 | $ 1,389.6 | |
Other OVEC Member [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Equity ownership interest | 4.90% | |
Other OVEC Member [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Equity ownership interest | 4.90% |
Contractual Obligations, Comm_4
Contractual Obligations, Commercial Commitments and Contingenciesl (Schedule Of Contractual Obligations And Commercial Commitments) (Details) $ in Millions | Dec. 31, 2018USD ($) |
Electricity Purchase Commitments [Member] | |
Contractual Obligations, Commercial Commitments And Contingencies [Line Items] | |
Electricity Purchase Commitments | $ 209.4 |
Electricity Purchase Agreements Less Than 1 Year | 139.5 |
Electricity Purchase Agreements in Years 2 and 3 | 69.9 |
Electricity Purchase Agreements in Years 4 and 5 | 0 |
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 | 209.4 |
Electricity Purchase Agreements Less Than 1 Year | 139.5 |
Electricity Purchase Agreements in Years 2 and 3 | 69.9 |
Electricity Purchase Agreements in Years 4 and 5 | 0 |
Electricity Purchase Agreements, After Year 5 | 0 |
Other Intangible Assets [Member] | |
Contractual Obligations, Commercial Commitments And Contingencies [Line Items] | |
Total Purchase orders and other contractual obligations | 40.2 |
Purchase orders and other contractual obligations, Less than 1 year | 11.4 |
Purchase orders and other contractual obligations, 2 - 3 years | 14.8 |
Purchase orders and other contractual obligations, 4 - 5 years | 14 |
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 | 39.8 |
Purchase orders and other contractual obligations, Less than 1 year | 11.3 |
Purchase orders and other contractual obligations, 2 - 3 years | 14.7 |
Purchase orders and other contractual obligations, 4 - 5 years | 13.8 |
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, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Jan. 01, 2016 | |
Related Party Transaction [Line Items] | ||||
Other Investments | $ 0.2 | $ 0.3 | ||
Deferred Compensation Arrangement with Individual, Compensation Expense | 0.4 | 0.4 | $ 0.5 | |
Sales to related party | 4.9 | 4.2 | 4.6 | |
Charges for Services Provided | 41 | 46.5 | 42.8 | |
Net payable to the Service Company | (4.8) | (3.9) | ||
Due to Affiliate | (0.5) | (0.6) | ||
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Related Party Transaction [Line Items] | ||||
Deferred Compensation Arrangement with Individual, Compensation Expense | 0.3 | 0.4 | 0.5 | |
Sales to related party | 4.9 | 4.2 | 4.5 | |
Charges for Services Provided | 25.7 | 39 | 38.7 | |
Net payable to the Service Company | (4.8) | (3.9) | ||
Premiums paid for Insurance Services provided by MVIC | 2.7 | 3.1 | 3.4 | |
Due to Affiliate | 0.5 | (4.8) | ||
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 | ||
Prepaid Expenses and Other Current Assets [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Related Party Transaction [Line Items] | ||||
Accounts Receivable, Related Parties, Current | 19.6 | 6.5 | ||
Other Current Liabilities [Member] | ||||
Related Party Transaction [Line Items] | ||||
Accounts Payable, Related Parties | ||||
Other Current Liabilities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Related Party Transaction [Line Items] | ||||
Accounts Payable, Related Parties | ||||
AES Ohio Generation [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Related Party Transaction [Line Items] | ||||
Charges for Services Provided | 0 | 5.4 | 8.7 | |
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) | |||
Income Taxes Paid, Net [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||||
Related Party Transaction [Line Items] | ||||
Related Party Transaction, Amounts of Transaction | 14.6 | 28.1 | 0 | |
Charges for health, welfare and benefit plans [Member] | Subsidiary of Common Parent [Member] | ||||
Related Party Transaction [Line Items] | ||||
Related Party Transaction, Amounts of Transaction | 7.9 | 15.4 | 9.6 | |
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 | 8.7 | 14.3 | 9.4 | |
Consulting Services [Member] | Subsidiary of Common Parent [Member] | ||||
Related Party Transaction [Line Items] | ||||
Related Party Transaction, Amounts of Transaction | 2 | 0 | 0 | |
Consulting 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 | 2 | 0 | 0 | |
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 | $ 7.1 | $ 3.7 | $ 5.7 |
Business Segments (Narrative) (
Business Segments (Narrative) (Details) | 12 Months Ended |
Dec. 31, 2018mi²segmentcustomer | |
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 | 1 |
Approximate number of retail customers | customer | 525,000 |
Service area, square miles | 6,000 |
Business Segments (Segment Fina
Business Segments (Segment Financial Information) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Segment Reporting Information [Line Items] | |||
External customer revenues | $ 775.9 | $ 743.9 | $ 834.2 |
Intersegment revenues | 0 | 0 | 0 |
Total revenues | 775.9 | 743.9 | 834.2 |
Fuel Costs | 17.5 | 9 | 17.4 |
Depreciation and amortization | 73.1 | 76.1 | 73.6 |
Interest expense | 98 | 110 | 107.4 |
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest | 31.9 | (6.5) | 12.4 |
Net loss from continuing operations | 31.2 | (1.5) | 14.8 |
Discontinued operations, net of tax | 38.9 | (93.1) | (500) |
Net income (loss) | 70.1 | (94.6) | (485.2) |
Cash capital expenditures | 103.6 | 121.5 | 148.5 |
Total assets (end of year) | 1,883.1 | 2,049.2 | 2,419.2 |
Fixed-asset impairment (Note 14) | 2.8 | 0 | 23.9 |
Operating Segments [Member] | Transmission and Distribution [Member] | |||
Segment Reporting Information [Line Items] | |||
External customer revenues | 737.8 | 718.9 | 806.7 |
Intersegment revenues | 0.9 | 1.1 | 1.3 |
Total revenues | 738.7 | 720 | 808 |
Depreciation and amortization | 74.5 | 75.3 | 71 |
Interest expense | 27.3 | 30.5 | 25.4 |
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest | 104.4 | 88.5 | 143 |
Cash capital expenditures | 93.1 | 85.6 | 83.4 |
Total assets (end of year) | 1,819.6 | 1,695.9 | 1,710.5 |
Fixed-asset impairment (Note 14) | 0 | 0 | |
Corporate, Non-Segment [Member] | |||
Segment Reporting Information [Line Items] | |||
External customer revenues | 38.1 | 25 | 27.5 |
Intersegment revenues | 2.9 | 4.4 | 5.7 |
Total revenues | 41 | 29.4 | 33.2 |
Depreciation and amortization | (1.4) | 0.8 | 2.6 |
Interest expense | 70.7 | 79.5 | 82.3 |
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest | (72.5) | (95) | (130.6) |
Cash capital expenditures | 10.5 | 35.9 | 65.1 |
Total assets (end of year) | 545.9 | 736.5 | 1,145.9 |
Fixed-asset impairment (Note 14) | 2.8 | 23.9 | |
Consolidation, Eliminations [Member] | |||
Segment Reporting Information [Line Items] | |||
External customer revenues | 0 | 0 | 0 |
Intersegment revenues | (3.8) | (5.5) | (7) |
Total revenues | (3.8) | (5.5) | (7) |
Depreciation and amortization | 0 | 0 | 0 |
Interest expense | 0 | 0 | (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) | (482.4) | (383.2) | (437.2) |
Fixed-asset impairment (Note 14) | 0 | 0 | |
THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
Segment Reporting Information [Line Items] | |||
Fuel Costs | 2.4 | 0.5 | 5.3 |
Depreciation and amortization | 74.5 | 75.3 | 71 |
Interest expense | 27.3 | 30.5 | 24.7 |
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest | 104.4 | 88.5 | 143.6 |
Net loss from continuing operations | 86.7 | 57.4 | 97.6 |
Discontinued operations, net of tax | 0 | (40.4) | (870.3) |
Net income (loss) | 86.7 | 17 | (772.7) |
Total assets (end of year) | 1,819.6 | 1,695.9 | |
Fixed-asset impairment (Note 14) | $ 0 | 66.3 | 1,353.5 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Generation [Member] | |||
Segment Reporting Information [Line Items] | |||
Discontinued operations, net of tax | $ (40.4) | $ (870.3) |
Revenue (Details)
Revenue (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Revenue from Contract with Customer, Excluding Assessed Tax | $ 743.8 | |
Revenues | 775.9 | |
RTO Revenue | 43.2 | |
RTO Capacity Revenue | 14.4 | |
Contract with Customer, Asset, Gross | 72.6 | $ 63 |
Utility [Member] | ||
Revenues | 738.7 | |
RTO Revenue | 43.1 | |
RTO Capacity Revenue | 7.8 | |
Corporate, Non-Segment [Member] | ||
Revenues | 41 | |
RTO Revenue | 0.1 | |
RTO Capacity Revenue | 6.6 | |
Consolidation, Eliminations [Member] | ||
Revenues | (3.8) | |
RTO Revenue | 0 | |
RTO Capacity Revenue | 0 | |
THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Revenue from Contract with Customer, Excluding Assessed Tax | 706.6 | |
Revenues | 738.7 | |
RTO Revenue | 43.1 | |
RTO Capacity Revenue | 7.8 | |
Contract with Customer, Asset, Gross | 70.1 | $ 62.1 |
Wholesale Revenue [Member] | ||
Revenue from Contract with Customer, Excluding Assessed Tax | 52 | |
Wholesale Revenue [Member] | Utility [Member] | ||
Revenue from Contract with Customer, Excluding Assessed Tax | 29.9 | |
Wholesale Revenue [Member] | Corporate, Non-Segment [Member] | ||
Revenue from Contract with Customer, Excluding Assessed Tax | 22.1 | |
Wholesale Revenue [Member] | Consolidation, Eliminations [Member] | ||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | |
Wholesale Revenue [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Revenue from Contract with Customer, Excluding Assessed Tax | 29.9 | |
Other Revenues [Member] | ||
Revenue from Contract with Customer, Excluding Assessed Tax | 9.4 | |
Other non-606 revenue | 0 | |
Other Revenues [Member] | Utility [Member] | ||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | |
Other non-606 revenue | 0 | |
Other Revenues [Member] | Corporate, Non-Segment [Member] | ||
Revenue from Contract with Customer, Excluding Assessed Tax | 9.4 | |
Other non-606 revenue | 2.8 | |
Other Revenues [Member] | Consolidation, Eliminations [Member] | ||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | |
Other non-606 revenue | (2.8) | |
Retail Revenue [Member] | ||
Revenue from Contract with Customer, Excluding Assessed Tax | 624.8 | |
Other non-606 revenue | 32.1 | |
Retail Revenue [Member] | Utility [Member] | ||
Revenue from Contract with Customer, Excluding Assessed Tax | 625.8 | |
Other non-606 revenue | 32.1 | |
Retail Revenue [Member] | Corporate, Non-Segment [Member] | ||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | |
Other non-606 revenue | 0 | |
Retail Revenue [Member] | Consolidation, Eliminations [Member] | ||
Revenue from Contract with Customer, Excluding Assessed Tax | (1) | |
Other non-606 revenue | 0 | |
Retail Revenue [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | ||
Revenue from Contract with Customer, Excluding Assessed Tax | 625.8 | |
Other non-606 revenue | $ 32.1 |
Discontinued Operations (Detail
Discontinued Operations (Details) - USD ($) $ in Millions | 12 Months Ended | ||||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2017 | Dec. 31, 2015 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||
Disposal Group, Including Discontinued Operation, Restricted Cash | $ 0 | $ 1.5 | |||
Deposit received on sale of DPLER | $ 75.5 | ||||
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax | (1.6) | 14 | $ 49.2 | ||
Accounts receivable, net | 4 | 37.9 | |||
Property, plant & equipment, net | 0 | 232.2 | |||
Intangible assets, net | 5.3 | 5.5 | |||
Total assets of the disposal group classified as held for sale in the balance sheets | 14 | 321.9 | |||
Accounts payable | 3.9 | 25.1 | |||
Total liabilities of the disposal group classified as held for sale in the balance sheets | 81.4 | 199.9 | |||
Revenues | 158.6 | 492.9 | 593 | ||
Cost of revenues | (74.3) | (249.5) | (349.6) | ||
Income / (loss) from discontinued operations before income tax | 70.5 | (127.4) | (806.4) | ||
Income tax expense / (benefit) from discontinued operations | 30 | (20.3) | (257.2) | ||
Net income / (loss) from discontinued operations | 38.9 | (93.1) | (500) | ||
Cash Provided by (Used in) Operating Activities, Discontinued Operations | (6.8) | 126.8 | 92.3 | ||
Cash Provided by (Used in) Investing Activities, Discontinued Operations | 233.8 | 51.8 | (56.8) | ||
Disposal Group, Including Discontinued Operation, Inventory | 0 | 19.4 | |||
Disposal Group, Including Discontinued Operations, Taxes Applicable to Subsequent Years | 2.3 | 7.4 | |||
Disposal Group, Including Discontinued Operation, Other Assets, Current | 2.4 | 17.4 | |||
Disposal Group, Including Discontinued Operation, Other Assets, Noncurrent | 0 | 0.6 | |||
Disposal Group, Including Discontinued Operation, Accrued Income Tax Payable | 3.1 | 6.3 | |||
Disposal Group, Including Discontinued Operation, Other Liabilities, Current | 5.2 | 30 | |||
Disposal Group, Including Discontinued Operations, Long-Term Debt | 0 | 0.3 | |||
Disposal Group, Including Discontinued Operation, Deferred Tax Liabilities | (39.8) | (2.3) | |||
Disposal Group, Including Discontinued Operation, Taxes Payable | 2.3 | 7.4 | |||
Disposal Group, Including Discontinued Operation, Pension Plan Benefit Obligation | 9.7 | 10.6 | |||
Asset Retirement Obligation, Held for Sale | 90.4 | 116.6 | |||
Disposal Group, Including Discontinued Operation, Other Liabilities, Noncurrent | 6.6 | 5.9 | |||
Disposal Group, Including Discontinued Operation, Operating and Other Expenses | (13.8) | (195) | (214.6) | ||
Disposal Group, Including Discontinued Operation, Fixed-Asset Impairment | 0 | (175.8) | (835.2) | ||
Long Term Indebtedness, Less than or Equal to | 750 | $ 750 | |||
Debt Percentage of Rate Base | 75.00% | ||||
Disposal Group, Including Discontinued Operation, Interest Expense | $ 0.2 | $ 0.5 | |||
Disposal Group, Including Discontinued Operation, Asset Retirement Obligation, Revision of Estimate | 27.6 | ||||
Miami Fort and Zimmer [Member] | |||||
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 | $ (14) | ||||
AES Ohio Generation peakers [Member] | |||||
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 | $ (1.9) | ||||
Utility [Member] | |||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||
Long-term Debt, Gross | $ 750 |
Generation Separation (Details)
Generation Separation (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | 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 | $ 750 | ||
Debt Percentage of Rate Base | 75.00% | |||
Cash Provided by (Used in) Operating Activities, Discontinued Operations | (6.8) | $ 126.8 | $ 92.3 | |
Cash Provided by (Used in) Investing Activities, Discontinued Operations | 233.8 | 51.8 | (56.8) | |
Disposal Group, Including Discontinued Operation, Restricted Cash | 0 | 1.5 | ||
Accounts receivable, net | 4 | 37.9 | ||
Disposal Group, Including Discontinued Operation, Inventory | 0 | 19.4 | ||
Disposal Group, Including Discontinued Operations, Taxes Applicable to Subsequent Years | 2.3 | 7.4 | ||
Property, plant & equipment, net | 0 | 232.2 | ||
Intangible assets, net | 5.3 | 5.5 | ||
Total assets of the disposal group classified as held for sale in the balance sheets | 14 | 321.9 | ||
Accounts payable | 3.9 | 25.1 | ||
Disposal Group, Including Discontinued Operation, Accrued Income Tax Payable | 3.1 | 6.3 | ||
Disposal Group, Including Discontinued Operations, Long-Term Debt | 0 | 0.3 | ||
Disposal Group, Including Discontinued Operation, Taxes Payable | 2.3 | 7.4 | ||
Disposal Group, Including Discontinued Operation, Deferred Tax Liabilities | (39.8) | (2.3) | ||
Disposal Group, Including Discontinued Operation, Pension Plan Benefit Obligation | 9.7 | 10.6 | ||
Asset Retirement Obligation, Held for Sale | 90.4 | 116.6 | ||
Total liabilities of the disposal group classified as held for sale in the balance sheets | 81.4 | 199.9 | ||
Revenues | 158.6 | 492.9 | 593 | |
Cost of revenues | (74.3) | (249.5) | (349.6) | |
Disposal Group, Including Discontinued Operation, Operating and Other Expenses | (13.8) | (195) | (214.6) | |
Disposal Group, Including Discontinued Operation, Fixed-Asset Impairment | 0 | (175.8) | (835.2) | |
Income / (loss) from discontinued operations before income tax | 70.5 | (127.4) | (806.4) | |
Income tax expense from discontinued operations | 30 | (20.3) | (257.2) | |
Net income / (loss) from discontinued operations | 38.9 | (93.1) | (500) | |
Disposal Group, Including Discontinued Operation, Interest Expense | 0.2 | 0.5 | ||
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 | $ 750 | ||
Debt Percentage of Rate Base | 75.00% | |||
Income / (loss) from discontinued operations before income tax | 0 | $ (56.3) | (1,338.7) | |
Income tax expense from discontinued operations | 0 | (15.9) | (468.4) | |
Net income / (loss) from discontinued operations | 0 | (40.4) | (870.3) | |
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 | |||
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 | 21.8 | 29.9 | ||
Cash Provided by (Used in) Investing Activities, Discontinued Operations | (3.5) | (39) | ||
Disposal Group, Including Discontinued Operation, Restricted Cash | 2 | |||
Accounts receivable, net | 31.3 | |||
Disposal Group, Including Discontinued Operation, Inventory | 42 | |||
Disposal Group, Including Discontinued Operations, Taxes Applicable to Subsequent Years | 1.8 | |||
Property, plant & equipment, net | 87 | |||
Intangible assets, net | 0.7 | |||
Other assets | 15.5 | |||
Total assets of the disposal group classified as held for sale in the balance sheets | 180.3 | |||
Accounts payable | 12.4 | |||
Disposal Group, Including Discontinued Operation, Accrued Income Tax Payable | (3.9) | |||
Disposal Group, Including Discontinued Operations, Long-Term Debt | 0.3 | |||
Disposal Group, Including Discontinued Operation, Deferred Tax Liabilities | (91.9) | |||
Disposal Group, Including Discontinued Operation, Pension Plan Benefit Obligation | 9.6 | |||
Disposal Group, Including Discontinued Operation, Accumulated Deferred Investment Tax Credit | 15.1 | |||
Asset Retirement Obligation, Held for Sale | 126.3 | |||
Other liabilities | 24.1 | |||
Total liabilities of the disposal group classified as held for sale in the balance sheets | 92 | |||
Disposal Group, Including Discontinued Operation, Accumulated Other Comprehensive Income (Loss), Net of Tax | 2.1 | |||
Disposal Group, Including Discontinued Operation, Net Assets | $ 10 | 0 | $ 86.2 | |
Revenues | 358.4 | 557.9 | ||
Cost of revenues | (191.6) | (341.1) | ||
Disposal Group, Including Discontinued Operation, Operating and Other Expenses | (156.8) | (202) | ||
Disposal Group, Including Discontinued Operation, Fixed-Asset Impairment | (66.3) | (1,353.5) | ||
Income / (loss) from discontinued operations before income tax | (56.3) | (1,338.7) | ||
Income tax expense from discontinued operations | (15.9) | (468.4) | ||
Net income / (loss) from discontinued operations | (40.4) | (870.3) | ||
Disposal Group, Including Discontinued Operation, Interest Expense | $ 0.2 | $ 0.5 |
Assets and Liabilities Held-F_3
Assets and Liabilities Held-For-Sale and Dispositions (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
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 | $ 31.9 | $ (6.5) | $ 12.4 |
Accounts receivable, net | 4 | 37.9 | |
Fixed-asset impairment (Note 14) | 2.8 | 0 | 23.9 |
Disposal Group, Including Discontinued Operation, Inventory | 0 | 19.4 | |
Disposal Group, Including Discontinued Operations, Taxes Applicable to Subsequent Years | 2.3 | 7.4 | |
Property, plant & equipment, net | 0 | 232.2 | |
Total assets of the disposal group classified as held for sale in the balance sheets | 14 | 321.9 | |
Accounts payable | 3.9 | 25.1 | |
Disposal Group, Including Discontinued Operation, Accrued Income Tax Payable | 3.1 | 6.3 | |
Disposal Group, Including Discontinued Operation, Taxes Payable | 2.3 | 7.4 | |
Asset Retirement Obligation, Held for Sale | 90.4 | 116.6 | |
Total liabilities of the disposal group classified as held for sale in the balance sheets | 81.4 | 199.9 | |
Proceeds from disposal and sale of business | 234.9 | 70.1 | 0 |
Gain (Loss) on Disposition of Business | (11.7) | 0 | 0 |
Property, Plant and Equipment, Additions | 103.6 | 121.5 | 148.5 |
Beckjord [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 | (11.7) | ||
Property, Plant and Equipment, Additions | 14.5 | ||
THE DAYTON POWER AND LIGHT COMPANY [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 | 104.4 | 88.5 | 143.6 |
Fixed-asset impairment (Note 14) | 0 | 66.3 | 1,353.5 |
Gain (Loss) on Disposition of Business | (12.4) | $ 0 | $ 0 |
THE DAYTON POWER AND LIGHT COMPANY [Member] | Beckjord [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 | (12.4) | ||
Property, Plant and Equipment, Additions | $ 14.5 |
Fixed-asset Impairment (Narrati
Fixed-asset Impairment (Narrative) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Public Utility, Property, Plant and Equipment [Line Items] | |||
Fixed-asset impairment (Note 14) | $ 2.8 | $ 0 | $ 23.9 |
Conesville [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Fixed-asset impairment (Note 14) | 23.9 | ||
Conesville [Member] | Fair Value, Inputs, Level 3 [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Fair Value | $ 1.1 |
Schedule II Valuation And Qua_2
Schedule II Valuation And Qualifying Accounts (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Provision for Uncollectible Accounts [Member] | |||
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items] | |||
Balance at Beginning of Period | $ 1,053 | $ 1,159 | $ 835 |
Additions | 3,411 | 3,141 | 4,113 |
Deductions | 3,574 | 3,247 | 3,789 |
Balance at End of Period | 890 | 1,053 | 1,159 |
Provision for Uncollectible Accounts [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | |||
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items] | |||
Balance at Beginning of Period | 1,053 | 1,159 | 835 |
Additions | 3,411 | 3,141 | 4,113 |
Deductions | 3,574 | 3,247 | 3,789 |
Balance at End of Period | 890 | 1,053 | 1,159 |
Valuation Allowance For Deferred Tax Assets [Member] | |||
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items] | |||
Balance at Beginning of Period | 36,328 | 38,266 | 39,874 |
Additions | 1,539 | 4,383 | 0 |
Deductions | 8,794 | 6,321 | 1,608 |
Balance at End of Period | $ 29,073 | $ 36,328 | $ 38,266 |