DPL (DPL) 10-Q 8 May 18 2018 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2018	May 08, 2018
Entity Registrant Name	DPL INC
Entity Central Index Key	787,250
Document Type	10-Q
Document Period End Date	Mar. 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		1
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q1
Entity Voluntary Filers	Yes
Entity Well-known Seasoned Issuer	No
THE DAYTON POWER AND LIGHT COMPANY [Member]
Entity Registrant Name	DAYTON POWER & LIGHT CO
Entity Central Index Key	27,430
Document Type	10-Q
Amendment Flag	false
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		41,172,173
Entity Voluntary Filers	Yes
Entity Well-known Seasoned Issuer	No

Condensed Consolidated Statemen

Condensed Consolidated Statements of Operations - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Revenues	$ 293.2	$ 323.9
Cost of revenues:
Net fuel cost	33.8	54.1
Net purchased power cost	97.8	102
Total cost of revenues	131.6	156.1
Gross margin	161.6	167.8
Operating expenses:
Operation and maintenance	55.1	82.7
Depreciation and amortization	20.1	28
General taxes	22.4	24.2
Impairment of Long-Lived Assets Held-for-use	0	66.4
Other	0.6	19.4
Other Operating Income (Expense), Net	14.9	18.2
Total operating expenses	112.5	219.5
Operating loss	49.1	(51.7)
Other income / (expense), net
Investment loss	(0.1)	0
Interest expense	(28)	(27.3)
Charge for early redemption of debt	(0.7)	0
Other expense	0.2	(4.2)
Total other expense, net	(28.6)	(31.5)
Loss from continuing operations before income tax	20.5	(83.2)
Income tax benefit from continuing operations	3.6	(31.5)
Net loss	16.9	(51.7)
THE DAYTON POWER AND LIGHT COMPANY [Member]
Revenues	196	190.1
Cost of revenues:
Net fuel cost	0.9	0
Net purchased power cost	83.8	81.1
Total cost of revenues	84.7	81.1
Gross margin	111.3	109
Operating expenses:
Operation and maintenance	32.2	38
Depreciation and amortization	18.6	18.1
General taxes	19.3	18.9
Impairment of Long-Lived Assets Held-for-use	0	66.3
Other	0	19.4
Other Operating Income (Expense), Net	12.4	0
Total operating expenses	82.5	75
Operating loss	28.8	34
Other income / (expense), net
Investment loss	(0.1)	0
Interest expense	(8.2)	(7.6)
Charge for early redemption of debt	(0.5)	0
Other expense	(0.7)	(1.4)
Total other expense, net	(9.5)	(9)
Loss from continuing operations before income tax	19.3	25
Income tax benefit from continuing operations	3.6	8
Net loss from continuing operations	15.7	17
Loss from discontinued operations	0	(88.7)
Income tax benefit for discontinued operations	0	(29.9)
Net income from discontinued operations	0	(58.8)
Net loss	$ 15.7	$ (41.8)

Condensed Consolidated Stateme3

Condensed Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Net income	$ 16.9	$ (51.7)
Available-for-sale securities activity:
Change in fair value of available-for-sale securities, net of income tax	0	0.2
Reclassification to earnings, net of income tax	0	(0.1)
AOCI reclassed to Retained Earnings, net of tax	(1)
Total change in fair value of available-for-sale securities	(1)	0.1
Derivative activity:
Change in derivative fair value, net of income tax	0.9	5.2
Reclassification of earnings, net of income tax	2.3	1
Total change in fair value of derivatives	3.2	6.2
Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), Reclassification Adjustment from AOCI, before Tax	0	(0.3)
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), Reclassification Adjustment from AOCI, after Tax	0	(1.2)
Pension and postretirement activity:
Reclassification to earnings, net of income tax	0.1	0.8
Total change in unfunded pension obligation	0.1	(0.7)
Other comprehensive income	2.3	5.6
Net comprehensive loss	19.2	(46.1)
THE DAYTON POWER AND LIGHT COMPANY [Member]
Net income	15.7	(41.8)
Available-for-sale securities activity:
Change in fair value of available-for-sale securities, net of income tax	0	0.2
Reclassification to earnings, net of income tax	0	(0.1)
AOCI reclassed to Retained Earnings, net of tax	(1.1)	0
Total change in fair value of available-for-sale securities	(1.1)	0.1
Derivative activity:
Change in derivative fair value, net of income tax	0.5	5.2
Reclassification of earnings, net of income tax	(0.3)	1
Total change in fair value of derivatives	0.2	6.2
Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), Reclassification Adjustment from AOCI, before Tax	0	(1.1)
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), Reclassification Adjustment from AOCI, after Tax	0	(0.5)
Pension and postretirement activity:
Reclassification to earnings, net of income tax	0.9	2.5
Total change in unfunded pension obligation	0.9	0.9
Other comprehensive income	0	7.2
Net comprehensive loss	15.7	(34.6)
Gains / (losses) on available-for-sale securities [Member]
Available-for-sale securities activity:
AOCI reclassed to Retained Earnings, net of tax	(1)	$ 0
Pension and postretirement activity:
Other comprehensive income	(1)
Gains / (losses) on available-for-sale securities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Available-for-sale securities activity:
AOCI reclassed to Retained Earnings, net of tax	(1.1)
Pension and postretirement activity:
Other comprehensive income	$ (1.1)

Condensed Consolidated Stateme4

Condensed Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Income tax (expense)/benefit on unrealized gains (losses) related to available-for-sale securities	$ 0	$ 0
Income tax (expense) benefit on reclassification to earnings	0	0
AOCI reclassed to Retained Earnings, income tax	0.6	0
Income tax (expense)/benefit on unrealized gains (losses) related to derivative activity	(0.1)	(2.8)
Income tax (expense)/benefit on reclassification of earnings related to derivative activity	0.8	(0.5)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), Reclassification Adjustment from AOCI, Tax	0	0.2
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax	0	0.7
Income tax (expense)/benefit on reclassification of earnings related to pension and postretirement activity	(0.1)	(0.5)
THE DAYTON POWER AND LIGHT COMPANY [Member]
Income tax (expense)/benefit on unrealized gains (losses) related to available-for-sale securities	0	0
Income tax (expense) benefit on reclassification to earnings	0	0
AOCI reclassed to Retained Earnings, income tax	0.6	0
Income tax (expense)/benefit on unrealized gains (losses) related to derivative activity	(0.1)	(2.8)
Income tax (expense)/benefit on reclassification of earnings related to derivative activity	0.5	(0.5)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), Reclassification Adjustment from AOCI, Tax	0	0.6
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax	0	0.3
Income tax (expense)/benefit on reclassification of earnings related to pension and postretirement activity	$ (0.2)	$ (1.3)

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 123.9	$ 24.5
Restricted cash	27.4	1.9
Accounts receivable, net	101.2	98.7
Inventories	22.3	24.5
Taxes applicable to subsequent years	55.3	73.8
Regulatory assets, current	21.3	23.9
Other prepayments and current assets	21.1	27.9
Assets Held-for-sale, Not Part of Disposal Group, Current	0	250.3
Total current assets	372.5	525.5
Property, plant & equipment:
Property, plant & equipment	1,589	1,554.7
Less: Accumulated depreciation and amortization	(291.8)	(278.6)
Property, plant and equipment, net of depreciation	1,297.2	1,276.1
Construction work in process	33.2	48.8
Total net property, plant & equipment	1,330.4	1,324.9
Other non-current assets:
Regulatory assets, non-current	159.7	163.2
Intangible assets, net of amortization	19.6	21.1
Other deferred assets	13.1	14.5
Total other non-current assets	192.4	198.8
Total assets	1,895.3	2,049.2
Current liabilities:
Current portion of long-term debt	105.6	4.7
Short-term debt	20	10
Accounts payable	71.5	70.1
Accrued taxes	84.5	80
Accrued interest	34.1	16.4
Security deposits	22.4	21.8
Regulatory liabilities, current	8.5	14.8
Insurance and claims costs	3	3
Other current liabilities	25.9	42.8
Liabilities Held for Sale, Current	0	13.2
Total current liabilities	375.5	276.8
Non-current liabilities:
Long-term debt	1,471	1,700.4
Deferred taxes	70.3	111.2
Taxes payable	39.9	77.4
Regulatory liabilities, non-current	221.9	221.2
Pension, retiree and other benefits	93.8	101
Asset Retirement Obligations, Noncurrent	128.3	131.2
Other deferred credits	14.1	14.3
Total non-current liabilities	2,039.3	2,356.7
Commitments and contingencies
Common shareholder's equity:
Common stock	0	0
Other paid-in capital	2,375	2,330.4
Accumulated other comprehensive income	3.1	0.8
Retained earnings/ (deficit)	(2,897.6)	(2,915.5)
Total common shareholder's equity	(519.5)	(584.3)
Total liabilities and shareholder's equity	1,895.3	2,049.2
THE DAYTON POWER AND LIGHT COMPANY [Member]
Current assets:
Cash and cash equivalents	1	5.2
Restricted cash	0.9	0.4
Accounts receivable, net	73	70.8
Inventories	7.6	7.3
Taxes applicable to subsequent years	53.3	71.1
Regulatory assets, current	21.3	23.9
Other prepayments and current assets	15.6	14.6
Total current assets	172.7	193.3
Property, plant & equipment:
Property, plant & equipment	2,274.8	2,247.2
Less: Accumulated depreciation and amortization	(996.3)	(987.3)
Property, plant and equipment, net of depreciation	1,278.5	1,259.9
Construction work in process	26.3	41.5
Total net property, plant & equipment	1,304.8	1,301.4
Other non-current assets:
Regulatory assets, non-current	159.7	163.2
Intangible assets, net of amortization	17.6	18.8
Other deferred assets	12.1	12.7
Total other non-current assets	189.4	194.7
Total assets	1,666.9	1,689.4
Current liabilities:
Current portion of long-term debt	4.6	4.6
Short-term debt	20	10
Accounts payable	50	46.6
Accrued taxes	69.4	70.1
Accrued interest	1.2	0.8
Security deposits	22.4	21.8
Regulatory liabilities, current	8.5	14.8
Other current liabilities	11.3	12.9
Total current liabilities	187.4	181.6
Non-current liabilities:
Long-term debt	583.1	642
Deferred taxes	134.3	131
Taxes payable	40.3	75.8
Regulatory liabilities, non-current	221.9	221.2
Pension, retiree and other benefits	84.3	91.1
Unamortized investment tax credit	0.8	0.9
Other deferred credits	6.8	7.1
Total non-current liabilities	1,076.2	1,177.1
Commitments and contingencies
Common shareholder's equity:
Common stock	0.4	0.4
Other paid-in capital	741.7	685.8
Accumulated other comprehensive income	(36.2)	(36.2)
Retained earnings/ (deficit)	(302.6)	(319.3)
Total common shareholder's equity	403.3	330.7
Total liabilities and shareholder's equity	$ 1,666.9	$ 1,689.4

Condensed Consolidated Balance6

Condensed Consolidated Balance Sheets (Parenthetical) - $ / shares	Mar. 31, 2018	Dec. 31, 2017
Common stock, shares authorized	1,500	1,500
Common stock, shares issued	1	1
Common stock, shares outstanding	1	1
THE DAYTON POWER AND LIGHT COMPANY [Member]
Common stock, shares authorized	250,000,000	250,000,000
Common stock, shares outstanding	41,172,173	41,172,173
Common stock, par value (in USD per share)	$ 0.01	$ 0.01

Condensed Consolidated Stateme7

Condensed Consolidated Statements of Cash Flows - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Cash flows from operating activities:
Net income	$ 16.9	$ (51.7)
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	20.1	28
Charge for early retirement of debt	0.7	0
Deferred income taxes	(41.7)	(4.7)
Impairment of Long-Lived Assets Held-for-use	0	66.4
Gain (Loss) on Disposition of Business	(13.6)	0
Gain (Loss) on Sale of Assets and Asset Impairment Charges	0.6	19.4
Changes in certain assets and liabilities:
Accounts receivable	5.9	38.1
Inventories	3.2	0.1
Taxes applicable to subsequent years	19.7	20.2
Deferred regulatory costs, net	(2.1)	(23.8)
Accounts payable	(0.9)	(30.9)
Accrued taxes payable	8.7	(66)
Accrued interest payable	17.6	15.9
Security deposits	0.6	17.6
Increase (Decrease) in Self Insurance Reserve	0	1.2
Increase (Decrease) in Obligation, Pension and Other Postretirement Benefits	(5.9)	1.3
Other	(6.4)	(4.6)
Net cash provided by operating activities	50.6	26.5
Cash flows from investing activities:
Capital expenditures	(27.3)	(41.4)
Proceeds from sale of business	234.9	0
Payments for Removal Costs	(14.5)	0
Insurance proceeds	2.8	1.2
Other investing activities, net	(0.5)	0.2
Net cash provided by investing activities	195.4	(40)
Cash flows from financing activities:
Repayments of Lines of Credit	(15)	0
Proceeds from Lines of Credit	25	0
Retirement of long-term debt	(131.1)	(7.4)
Net cash provided by financing activities	(121.1)	(7.4)
Cash and cash equivalents:
Net change	124.9	(20.9)
Supplemental cash flow information:
Interest paid, net of amounts capitalized	7	10.4
Non-cash financing and investing activities:
Accruals for capital expenditures	8.9	10.7
Restricted Cash and Cash Equivalents	151.3	62.7
Non-cash Proceeds from Sale of Business	4.1	0
Non-cash capital contribution	45.1	0
THE DAYTON POWER AND LIGHT COMPANY [Member]
Cash flows from operating activities:
Net income	15.7	(41.8)
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	18.6	23.5
Charge for early retirement of debt	0.5	0
Deferred income taxes	3.6	0.4
Impairment of Long-Lived Assets Held-for-use	0	66.3
Gain (Loss) on Disposition of Business	(12.4)	0
Gain (Loss) on Sale of Assets and Asset Impairment Charges	0	19.4
Changes in certain assets and liabilities:
Accounts receivable	(2.3)	28.4
Inventories	(0.2)	0.1
Taxes applicable to subsequent years	17.8	19.8
Deferred regulatory costs, net	(2.1)	(23.8)
Accounts payable	7.7	(24.6)
Accrued taxes payable	(36.3)	(52.7)
Accrued interest payable	0.3	(1.3)
Security deposits	0.6	17.6
Increase (Decrease) in Obligation, Pension and Other Postretirement Benefits	(5.5)	1.3
Other	(0.2)	(0.8)
Net cash provided by operating activities	30.6	31.8
Cash flows from investing activities:
Capital expenditures	(24.6)	(34.1)
Payments for Removal Costs	(14.5)	0
Other investing activities, net	(0.3)	0.1
Net cash provided by investing activities	(39.4)	(34)
Cash flows from financing activities:
Repayments of Lines of Credit	(15)	0
Proceeds from Lines of Credit	25	0
Retirement of long-term debt	(61.1)	(1.1)
Payments of Ordinary Dividends, Common Stock	(23.8)	(9)
Issuance of short-term debt - related party	0	30
Repayments of Related Party Debt	0	(35)
Proceeds from Contributions from Parent	80	0
Net cash provided by financing activities	5.1	(15.1)
Cash and cash equivalents:
Net change	(3.7)	(17.3)
Supplemental cash flow information:
Interest paid, net of amounts capitalized	5.5	7.9
Non-cash financing and investing activities:
Accruals for capital expenditures	4.6	8.7
Restricted Cash and Cash Equivalents	$ 1.9	$ 13.3

Overview and Summary of Signifi

Overview and Summary of Significant Accounting Policies	3 Months Ended
	Mar. 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 two reportable segments: the T&D segment and the Generation segment. See Note 12 – Business Segments for more information relating to these reportable segments. The terms “we,” “us,” “our” and “ours” are used to refer to DPL and its subsidiaries. DPL is an indirectly wholly-owned subsidiary of AES. DP&L , a wholly-owned subsidiary of DPL , is a public utility incorporated in 1911 under the laws of Ohio. Beginning in 2001, Ohio law gave Ohio consumers the right to choose the electric generation supplier from whom they purchase retail generation service; however, retail transmission and distribution services are still regulated. DP&L has the exclusive right to provide such transmission and distribution services to approximately 523,000 customers located in West Central Ohio. Additionally, 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. Through September 30, 2017, DP&L owned undivided interests in multiple coal-fired and peaking electric generating facilities as well as numerous transmission facilities. On October 1, 2017, the DP&L -owned generating facilities were transferred to AES Ohio Generation, an affiliate of DP&L and wholly-owned subsidiary of DPL , through an asset contribution agreement to a subsidiary that was merged into AES Ohio Generation. Principal industries located in DP&L’s service territory include automotive, food processing, paper, plastic, health care, data management, manufacturing and defense. DP&L's distribution sales reflect the general economic conditions, seasonal weather patterns, the proliferation of energy efficiency and distributed renewable resources and the market price of electricity. Through September 30, 2017, DP&L sold its generated energy and capacity into the wholesale market. After September 30, 2017, DP&L continues to sell its proportional share of energy and capacity from its investment in OVEC. DPL’s other significant subsidiaries include MVIC and AES Ohio Generation. MVIC is our captive insurance company that provides insurance services to DPL and our other subsidiaries. AES Ohio Generation owns and operates certain coal-fired generating facilities . AES Ohio Generation sells all of its energy and capacity into the wholesale market. DPL's subsidiaries are all wholly-owned. DPL also has a wholly-owned business trust, DPL Capital Trust II, formed for the purpose of issuing trust capital securities to investors. DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates, and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs. DPL and its subsidiaries employed 1,051 people as of March 31, 2018 , of which 673 were employed by DP&L . Approximately 59% of all DP&L and AES Ohio Generation employees are under a collective bargaining agreement. The current agreement, after initially being extended, expired on January 31, 2018. Under national labor law, all the terms and conditions of the expired agreement continue indefinitely, subject to certain exceptions. Notably, the union has the right to strike and DP&L and AES Ohio Generation have the right to lock out employees. We are continuing to negotiate with the union to enter into a new collective bargaining agreement. Currently, we are unable to predict the eventual outcome of these negotiations and have contingency plans to continue our operations if the negotiations are not successful. If we are not able to reach an agreement on terms favorable to us or to effectively implement our plans in the event that agreement is not reached, our results of operations, financial position and cash flows could be adversely impacted. Financial Statement Presentation DPL’s Condensed 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. As of March 31, 2018 , DPL has undivided ownership interests in three coal-fired generating facilities and numerous transmission facilities, all of which are included in the financial statements at the lower of depreciated historical cost or fair value, if impaired. Operating revenues and expenses of these facilities are included on a pro rata basis in the corresponding lines in the Condensed Consolidated Statements of Operations. Certain immaterial amounts from prior periods have been reclassified to conform to the current period presentation. All material intercompany accounts and transactions are eliminated in consolidation. These financial statements have been prepared in accordance with GAAP for interim financial statements, the instructions of Form 10-Q and Regulation S-X. Accordingly, certain information and footnote disclosures normally included in the annual financial statements prepared in accordance with GAAP have been omitted from this interim report. Therefore, our interim financial statements in this report should be read along with the annual financial statements included in our Form 10-K for the fiscal year ended December 31, 2017 . In the opinion of our management, the Condensed Consolidated Financial Statements presented in this report contain all adjustments necessary to fairly state our financial position as of March 31, 2018 ; our results of operations for the three months ended March 31, 2018 and 2017 and our cash flows for the three months ended March 31, 2018 and 2017 . Unless otherwise noted, all adjustments are normal and recurring in nature. Due to various factors, including, but not limited to, seasonal weather variations, the timing of outages of EGUs, changes in economic conditions involving commodity prices and competition, and other factors, interim results for the three months ended March 31, 2018 may not be indicative of our results that will be realized for the full year ending December 31, 2018 . 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: recognition of revenue including unbilled revenues, the carrying value of property, plant and equipment; 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; liabilities recorded for income tax exposures; litigation; contingencies; the valuation of AROs; and assets and liabilities related to employee benefits. Cash, Cash Equivalents, and Restricted Cash The following table provides a summary of cash, cash equivalents, and restricted cash amounts reported on the Condensed Consolidated Balance Sheet that reconcile to the total of such amounts as shown on the Condensed Consolidated Statements of Cash Flows: $ in millions March 31, 2018 December 31, 2017 Cash and cash equivalents $ 123.9 $ 24.5 Restricted cash 27.4 1.9 Cash, Cash Equivalents, and Restricted Cash, End of Period $ 151.3 $ 26.4 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. These taxes are accounted for on a net basis and not included in revenue. The amounts of such taxes collected for the three months ended March 31, 2018 and 2017 were $13.1 million and $12.5 million, respectively. 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. ASU Number and Name Description Date of Adoption Effect on the financial statements upon adoption New Accounting Standards Adopted 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities This standard requires equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) be measured at fair value with changes in fair value recognized in net income. However, an entity may choose to measure equity investments that do not have readily determinable fair values at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or a similar investment of the same issuer. 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 Retained Earnings. 2017-07, Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost This standard changes the presentation of non-service cost expense associated with defined benefit plans and updates the guidance so that only the service cost component will be eligible for capitalization. January 1, 2018 The adoption of this standard resulted in a $3.6 million reclassification of non-service pension and other postretirement benefit costs from Operating expense to Other income / (deductions) - net for the three months ended March 31, 2017. 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 The adoption of this standard resulted in a $20.6 million decrease in investing activities for the three months ended March 31, 2017. 2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-05, 2017-13 Revenue from Contracts with Customers (Topic 606) See " Adoption of FASC Topic 606, Revenue from Contracts with Customers " 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 ("ASC 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 ASC 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, ASC 605. 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 Condensed Consolidated Balance Sheet resulting from the adoption of FASC 606. See additional disclosures under ASC 606 in Note 13 – Revenue . 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. ASU Number and Name 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. We are currently evaluating the impact of adopting the standard on our consolidated financial statements. 2017-12, Derivatives and Hedging (Topic 815): Targeted improvements to Accounting for Hedging Activities The standard updates the hedge accounting model to expand the ability to hedge nonfinancial and financial risk components, reduce complexity, and ease certain documentation and assessment requirements. When facts and circumstances are the same as at the previous quantitative test, a subsequent quantitative effectiveness test is not required. The standard also eliminates the requirement to separately measure and report hedge ineffectiveness. For cash flow hedges, this means that the entire change in the fair value of a hedging instrument will be recorded in other comprehensive income and amounts deferred will be reclassified to earnings in the same income statement line as the hedged item. January 1, 2019. We are currently evaluating the impact of adopting the standard on our consolidated financial statements. 2017-08, Receivables - Nonrefundable Fees and Other Costs (Subtopic 310-20): Premium Amortization on Purchased Callable Debt Securities This standard shortens the period of amortization of the premium on certain callable debt securities to the earliest call date. January 1, 2019. We are currently evaluating the impact of adopting the standard on our consolidated financial statements. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments This standard updates the impairment model for financial assets measured at amortized cost to an expected loss model rather than an incurred loss model. It also allows for the presentation of credit losses on available-for-sale debt securities as an allowance rather than a write down. January 1, 2020. We are currently evaluating the impact of adopting the standard on our consolidated financial statements. 2016-02, 2018-01, Leases (Topic 842) See " 2016-02, Leases (Topic 842) " below. January 1, 2019. We are currently evaluating the impact of adopting the standard on our consolidated financial statements. 2016-02, 2018-01, Leases (Topic 842) 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 current accounting methods. For Lessors, the guidance modifies the lease classification criteria and the accounting for sales-type and direct financing leases. The guidance also eliminates current real estate-specific provisions. The standard must be adopted using a modified retrospective adoption at the beginning of the earliest comparative period presented in the financial statements (January 1, 2017). The FASB proposed amending the standard to give another option for transition. The proposed transition method would allow entities to not apply the new lease standard in the comparative periods presented in their financial statements in the year of adoption. Under the proposed transition method, the entity would apply the transition provisions on January 1, 2019 (i.e., the effective date). At transition, lessees and lessors are permitted to make an election to apply a package of practical expedients that allow them not to reassess: (1) whether any expired or existing contracts are or contain leases, (2) lease classification for any expired or existing leases, and (3) whether initial direct costs for any expired or existing leases qualify for capitalization under FASC 842. These three practical expedients must be elected as a package and must be consistently applied to all leases. Furthermore, entities are also permitted to make an election to use hindsight when determining lease term and entities can elect to use hindsight when assessing the impairment of right-of-use assets. We have established a task force focused on the identification of contracts that would be under the scope of the new standard and on the assessment and measurement of the right-of-use asset and related liability. Additionally, the implementation team has been working on the identification and selection of a lease accounting system that would support the implementation and the subsequent accounting. The implementation team is in the process of evaluating changes to our business processes, systems and controls to support recognition and disclosure under the new standard. As we have preliminarily concluded that at transition we would be using the package of practical expedients, the main impact expected as of the effective date is the recognition of the right to use asset and the related liability in the financial statements for all those contracts that contain a lease and for which we are the lessee. However, income statement presentation and the expense recognition pattern are not expected to change. Under FASC 842, it is expected that fewer contracts will contain a lease. However, due to the elimination of today's real estate-specific guidance and changes to certain lessor classification criteria, more leases will qualify as sales-type leases and direct financing leases. Under these two models, a lessor will derecognize the asset and will recognize a lease receivable. According to FASC 842, the lease receivable does not include variable payments that depend on the use of the asset (e.g. MWh produced by a facility). Therefore, the lease receivable could be lower than the carrying amount of the underlying asset at lease commencement. In such circumstances, the difference between the initially recognized lease receivable and the carrying amount of the underlying asset is recognized as a selling loss at lease commencement.
THE DAYTON POWER AND LIGHT COMPANY [Member]
Significant Accounting Policies [Line Items]
Overview and Summary of Significant Accounting Policies	Overview and Summary of Significant Accounting Policies Description of Business DP&L is a public utility incorporated in 1911 under the laws of Ohio. Beginning in 2001, Ohio law gave Ohio consumers the right to choose the electric generation supplier from whom they purchase retail generation service; however, retail transmission and distribution services are still regulated. DP&L has the exclusive right to provide such transmission and distribution services to approximately 523,000 customers located in West Central Ohio. Additionally, 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. Through September 30, 2017, DP&L owned undivided interests in multiple coal-fired and peaking electric generating facilities as well as numerous transmission facilities. On October 1, 2017, the DP&L -owned generating facilities were transferred to AES Ohio Generation, an affiliate of DP&L and wholly-owned subsidiary of DPL , through an asset contribution agreement to a subsidiary that was merged into AES Ohio Generation. 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 have either been closed or sold. Principal industries located in DP&L’s service territory include automotive, food processing, paper, plastic, health care, data management, manufacturing and defense. DP&L's distribution sales reflect the general economic conditions, seasonal weather patterns, the proliferation of energy efficiency and distributed renewable resources and the market price of electricity. Through September 30, 2017, DP&L sold its generated energy and capacity into the wholesale market. After September 30, 2017, DP&L continues to sell its proportional share of energy and capacity from its investment in OVEC. DP&L is a subsidiary of DPL . The terms “we,” “us,” “our” and “ours” are used to refer to DP&L . DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates, and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs. DP&L employed 673 people as of March 31, 2018 . Approximately 53% of DP&L employees are under a collective bargaining agreement. The current agreement, after initially being extended, expired on January 31, 2018. Under national labor law, all the terms and conditions of the expired agreement continue indefinitely, subject to certain exceptions. Notably, the union has the right to strike and DP&L has the right to lock out employees. We are continuing to negotiate with the union to enter into a new collective bargaining agreement. Currently, we are unable to predict the eventual outcome of these negotiations and have contingency plans to continue our operations if the negotiations are not successful. If we are not able to reach an agreement on terms favorable to us or to effectively implement our plans in the event that agreement is not reached, our results of operations, financial position and cash flows could be adversely impacted. Financial Statement Presentation DP&L does not have any subsidiaries. Certain immaterial amounts from prior periods have been reclassified to conform to the current period presentation. These financial statements have been prepared in accordance with GAAP for interim financial statements, the instructions of Form 10-Q and Regulation S-X. Accordingly, certain information and footnote disclosures normally included in the annual financial statements prepared in accordance with GAAP have been omitted from this interim report. Therefore, our interim financial statements in this report should be read along with the annual financial statements included in our Form 10-K for the fiscal year ended December 31, 2017 . In the opinion of our management, the Condensed Financial Statements presented in this report contain all adjustments necessary to fairly state our financial position as of March 31, 2018 ; our results of operations for the three months ended March 31, 2018 and 2017 and our cash flows for the three months ended March 31, 2018 and 2017 . Unless otherwise noted, all adjustments are normal and recurring in nature. Due to various factors, including, but not limited to, seasonal weather variations, the timing of outages of EGUs, changes in economic conditions involving commodity prices and competition, and other factors, interim results for the three months ended March 31, 2018 may not be indicative of our results that will be realized for the full year ending December 31, 2018 . 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: recognition of revenue including unbilled revenues, the carrying value of property, plant and equipment; 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; liabilities recorded for income tax exposures; litigation; contingencies; the valuation of AROs; and assets and liabilities related to employee benefits. Cash, Cash Equivalents, and Restricted Cash The following table provides a summary of cash, cash equivalents, and restricted cash amounts reported on the Condensed Balance Sheet that reconcile to the total of such amounts as shown on the Condensed Statements of Cash Flows: $ in millions March 31, 2018 December 31, 2017 Cash and cash equivalents $ 1.0 $ 5.2 Restricted cash 0.9 0.4 Cash, Cash Equivalents, and Restricted Cash, End of Period $ 1.9 $ 5.6 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. These taxes are accounted for on a net basis and not included in revenue. The amounts of such taxes collected for the three months ended March 31, 2018 and 2017 were $13.1 million and $12.5 million, respectively. New Accounting Pronouncements adopted in 2018 – The following table provides a brief description of recently adopted accounting pronouncements that had an impact on our 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. ASU Number and Name Description Date of Adoption Effect on the financial statements upon adoption New Accounting Standards Adopted 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities This standard requires equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) be measured at fair value with changes in fair value recognized in net income. However, an entity may choose to measure equity investments that do not have readily determinable fair values at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or a similar investment of the same issuer. 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. 2017-07, Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost This standard changes the presentation of non-service cost expense associated with defined benefit plans and updates the guidance so that only the service cost component will be eligible for capitalization. January 1, 2018 The adoption of this standard resulted in a $0.8 million reclassification of non-service pension and other postretirement benefit costs from Operating expense to Other income / (deductions) - net for the three months ended March 31, 2017. ASU Number and Name Description Date of Adoption Effect on the financial statements upon adoption 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 The adoption of this standard resulted in a $20.6 million decrease in investing activities for the three months ended March 31, 2017. 2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-05, 2017-13 Revenue from Contracts with Customers (Topic 606) See " Adoption of FASC Topic 606, Revenue from Contracts with Customers " 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 ("ASC 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 ASC 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, ASC 605. 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 Condensed Consolidated Balance Sheet resulting from the adoption of FASC 606. See additional disclosures under ASC 606 in Note 12 – Revenue . 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 financial statements. ASU Number and Name 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. We are currently evaluating the impact of adopting the standard on our financial statements. ASU Number and Name Description Date of Adoption Effect on the financial statements upon adoption 2017-12, Derivatives and Hedging (Topic 815): Targeted improvements to Accounting for Hedging Activities The standard updates the hedge accounting model to expand the ability to hedge nonfinancial and financial risk components, reduce complexity, and ease certain documentation and assessment requirements. When facts and circumstances are the same as at the previous quantitative test, a subsequent quantitative effectiveness test is not required. The standard also eliminates the requirement to separately measure and report hedge ineffectiveness. For cash flow hedges, this means that the entire change in the fair value of a hedging instrument will be recorded in other comprehensive income and amounts deferred will be reclassified to earnings in the same income statement line as the hedged item. January 1, 2019. We are currently evaluating the impact of adopting the standard on our financial statements. 2017-08, Receivables - Nonrefundable Fees and Other Costs (Subtopic 310-20): Premium Amortization on Purchased Callable Debt Securities This standard shortens the period of amortization of the premium on certain callable debt securities to the earliest call date. January 1, 2019. We are currently evaluating the impact of adopting the standard on our financial statements. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments This standard updates the impairment model for financial assets measured at amortized cost to an expected loss model rather than an incurred loss model. It also allows for the presentation of credit losses on available-for-sale debt securities as an allowance rather than a write down. January 1, 2020. We are currently evaluating the impact of adopting the standard on our financial statements. 2016-02, 2018-01, Leases (Topic 842) See " 2016-02, Leases (Topic 842) " below. January 1, 2019. We are currently evaluating the impact of adopting the standard on our financial statements. 2016-02, 2018-01, Leases (Topic 842) 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 current accounting methods. For Lessors, the guidance modifies the lease classification criteria and the accounting for sales-type and direct financing leases. The guidance also eliminates current real estate-specific provisions. The standard must be adopted using a modified retrospective adoption at the beginning of the earliest comparative period presented in the financial statements (January 1, 2017). The FASB proposed amending the standard to give another option for transition. The proposed transition method would allow entities to not apply the new lease standard in the comparative periods presented in their financial statements in the year of adoption. Under the proposed transition method, the entity would apply the transition provisions on January 1, 2019 (i.e., the effective date). At transition, lessees and lessors are permitted to make an election to apply a package of practical expedients that allow them not to reassess: (1) whether any expired or existing contracts are or contain leases, (2) lease classification for any expired or existing leases, and (3) whether initial direct costs for any expired or existing leases qualify for capitalization under FASC 842. These three practical expedients must be elected as a package and must be consistently applied to all leases. Furthermore, entities are also permitted to make an election to use hindsight when determining lease term and entities can elect to use hindsight when assessing the impairment of right-of-use assets. We have established a task force focused on the identification of contracts that would be under the scope of the new standard and on the assessment and measurement of the right-of-use asset and related liability. Additionally, the implementation team has been working on the identification and selection of a lease accounting system that would support the implementation and the subsequent accounting. The implementation team is in the process of evaluating changes to our business processes, systems and controls to support recognition and disclosure under the new standard. As we have preliminarily concluded that at transition we would be using the package of practical expedients, the main impact expected as of the effective date is the recognition of the right to use asset and the related liability in the financial statements for all those contracts that contain a lease and for which we are the lessee. However, income statement presentation and the expense recognition pattern are not expected to change. Under FASC 842, it is expected that fewer contracts will contain a lease. However, due to the elimination of today's real estate-specific guidance and changes to certain lessor classification criteria, more leases will qualify as sales-type leases and direct financing leases. Under these two models, a lessor will derecognize the asset and will recognize a lease receivable. According to FASC 842, the lease receivable does not include variable payments that depend on the use of the asset (e.g. MWh produced by a facility). Therefore, the lease receivable could be lower than the carrying amount of the underlying asset at lease commencement. In such circumstances, the difference between the initially recognized lease receivable and the carrying amount of the underlying asset is recognized as a selling loss at lease commencement.

Supplemental Financial Informat

Supplemental Financial Information	3 Months Ended
	Mar. 31, 2018
Supplemental Financial Information [Line Items]
Supplemental Financial Information	Supplemental Financial Information Accounts receivable and Inventories are as follows at March 31, 2018 and December 31, 2017 : March 31, December 31, $ in millions 2018 2017 Accounts receivable, net: Unbilled revenue $ 12.1 $ 18.0 Customer receivables 65.7 57.8 Amounts due from partners in jointly-owned plants 13.6 19.1 Other 10.9 4.9 Provision for uncollectible accounts (1.1 ) (1.1 ) Total accounts receivable, net $ 101.2 $ 98.7 Inventories, at average cost: Fuel and limestone $ 13.3 $ 15.5 Plant materials and supplies 8.4 8.5 Other 0.6 0.5 Total inventories, at average cost $ 22.3 $ 24.5 Accumulated Other Comprehensive Income / (Loss) The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the three months ended March 31, 2018 and 2017 are as follows: Details about Accumulated Other Comprehensive Income / (Loss) components Affected line item in the Condensed Consolidated Statements of Operations Three months ended March 31, $ in millions 2018 2017 Gains and losses on equity securities (Note 5): Other income $ — $ (0.1 ) Retained earnings (1.6 ) — Tax expense 0.6 — Net of income taxes (1.0 ) (0.1 ) Gains and losses on cash flow hedges (Note 6): Interest expense (1.1 ) (0.3 ) Revenue (2.0 ) (1.5 ) Purchased power 6.2 3.3 Total before income taxes 3.1 1.5 Tax benefit (0.8 ) (0.5 ) Net of income taxes 2.3 1.0 Amortization of defined benefit pension items (Note 9): Operation and maintenance 0.2 1.3 Tax benefit (0.1 ) (0.5 ) Net of income taxes 0.1 0.8 Total reclassifications for the period, net of income taxes $ 1.4 $ 1.7 The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the three months ended March 31, 2018 are as follows: $ in millions Gains / (losses) on equity securities Gains / (losses) on cash flow hedges Change in unfunded pension obligation Total Balance at January 1, 2018 $ 1.0 $ 14.7 $ (14.9 ) $ 0.8 Other comprehensive income before reclassifications — 0.9 — 0.9 Amounts reclassified from accumulated other comprehensive income / (loss) to earnings — 2.3 0.1 2.4 Amounts reclassified from accumulated other comprehensive income / (loss) to Retained earnings (1.0 ) — — (1.0 ) Net current period other comprehensive income / (loss) (1.0 ) 3.2 0.1 2.3 Balance at March 31, 2018 $ — $ 17.9 $ (14.8 ) $ 3.1 Operating expenses - other Operating expenses - other generally includes gains or losses on asset sales or dispositions, insurance recoveries, gains or losses on the sale of businesses and other expense or income from miscellaneous transactions. The components are summarized as follows: Three months ended March 31, $ in millions 2018 2017 Loss on asset disposal, net $ 0.6 $ 19.4 Loss on disposal and sale of businesses 13.6 — Insurance recoveries — (1.2 ) Other 0.7 — Net other expense / (income) $ 14.9 $ 18.2
THE DAYTON POWER AND LIGHT COMPANY [Member]
Supplemental Financial Information [Line Items]
Supplemental Financial Information	Supplemental Financial Information Accounts receivable and Inventories are as follows at March 31, 2018 and December 31, 2017 : March 31, December 31, $ in millions 2018 2017 Accounts receivable, net: Unbilled revenue $ 12.1 $ 18.0 Customer receivables 49.8 44.2 Amounts due from affiliates 3.8 — Amounts due from partners in jointly-owned plants 2.1 5.0 Other 6.3 4.7 Provision for uncollectible accounts (1.1 ) (1.1 ) Total accounts receivable, net $ 73.0 $ 70.8 Inventories, at average cost: Plant materials and supplies $ 7.0 $ 6.9 Other 0.6 0.4 Total inventories, at average cost $ 7.6 $ 7.3 Accumulated Other Comprehensive Income / (Loss) The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the three months ended March 31, 2018 and 2017 are as follows: Details about Accumulated Other Comprehensive Income / (Loss) components Affected line item in the Condensed Statements of Operations Three months ended March 31, $ in millions 2018 2017 Gains and losses on equity securities activity (Note 5): Other income $ — $ (0.1 ) Retained earnings (1.7 ) — Tax benefit 0.6 — Net of income taxes (1.1 ) (0.1 ) Gains and losses on cash flow hedges (Note 6): Interest expense (0.8 ) (0.3 ) Tax benefit from continuing operations 0.5 0.1 Gain from discontinued operations — 1.8 Tax expense from discontinued operations — (0.6 ) Net of income taxes (0.3 ) 1.0 Amortization of defined benefit pension items (Note 9): Operation and maintenance 1.1 3.8 Tax expense (0.2 ) (1.3 ) Net of income taxes 0.9 2.5 Total reclassifications for the period, net of income taxes $ (0.5 ) $ 3.4 The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the three months ended March 31, 2018 are as follows: $ in millions Gains / (losses) on equity securities Gains / (losses) on cash flow hedges Change in unfunded pension obligation Total Balance at January 1, 2018 $ 1.1 $ 1.4 $ (38.7 ) $ (36.2 ) Other comprehensive income before reclassifications — 0.5 — 0.5 Amounts reclassified from accumulated other comprehensive income / (loss) to earnings — (0.3 ) 0.9 0.6 Amounts reclassified from accumulated other comprehensive income / (loss) to Retained earnings (1.1 ) — — (1.1 ) Net current period other comprehensive income / (loss) (1.1 ) 0.2 0.9 — Balance at March 31, 2018 $ — $ 1.6 $ (37.8 ) $ (36.2 )

Regulatory Matters (Notes)

Regulatory Matters (Notes)	3 Months Ended
	Mar. 31, 2018
Schedule of Regulatory Assets and Liabilities [Text Block]	Regulatory Matters On November 30, 2015, DP&L filed a distribution rate case using a 12-month test year of June 1, 2015 to May 31, 2016 to measure revenue and expenses and a date certain of September 30, 2015 to measure its asset base. DP&L is seeking an increase to distribution revenues of $65.8 million per year. DP&L has asked for recovery of certain regulatory assets as well as two new riders that would allow DP&L to recover certain costs on an ongoing basis. It has proposed a modified rate design, which would increase the monthly customer charge, in an effort to decouple distribution revenues from electric sales. If approved as filed, the rates are expected to increase a typical residential customer bill approximately 4% based on rates in effect at the time of the filing. On March 12, 2018, the PUCO Staff filed its Staff Report of Investigation in the distribution rate case. In response, DP&L submitted objections and supplemental testimony on April 11, 2018. The PUCO has set the evidentiary hearing in this case for June 6, 2018. 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. This did not have a material impact to our financial statements during the three months ended March 31, 2018. Under the terms of the ESP, DPL will not make tax sharing payments and if DP&L's rates are reduced as a result of the TCJA, our cash flows could be adversely affected. At this time, we are unable to determine whether any of the above issues may have a material impact in the future on DP&L's business, financial condition, results of operations or cash flows. On March 15, 2018, the FERC initiated “show cause” proceedings against DP&L and numerous other utilities that had stated transmission rates, directing each utility to file either revised transmission rates to reflect the effects of the TCJA or to show cause why no changes in transmission rates were appropriate. DP&L intends to file new transmission rates in response to the show cause order. Because the filing will then be subject to review by the FERC and any interveners, DP&L is unable to determine the impact of the proceeding at this time.
Subsidiaries [Member]
Schedule of Regulatory Assets and Liabilities [Text Block]	Regulatory Matters On November 30, 2015, DP&L filed a distribution rate case using a 12-month test year of June 1, 2015 to May 31, 2016 to measure revenue and expenses and a date certain of September 30, 2015 to measure its asset base. DP&L is seeking an increase to distribution revenues of $65.8 million per year. DP&L has asked for recovery of certain regulatory assets as well as two new riders that would allow DP&L to recover certain costs on an ongoing basis. It has proposed a modified rate design, which would increase the monthly customer charge, in an effort to decouple distribution revenues from electric sales. If approved as filed, the rates are expected to increase a typical residential customer bill approximately 4% based on rates in effect at the time of the filing. On March 12, 2018, the PUCO Staff filed its Staff Report of Investigation in the distribution rate case. In response, DP&L submitted objections and supplemental testimony on April 11, 2018. The PUCO has set the evidentiary hearing in this case for June 6, 2018. 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. This did not have a material impact to our financial statements during the three months ended March 31, 2018. At this time, we are unable to determine whether any of the above issues may have a material impact in the future on DP&L's business, financial condition, results of operations or cash flows. On March 15, 2018, the FERC initiated “show cause” proceedings against DP&L and numerous other utilities that had stated transmission rates, directing each utility to file either revised transmission rates to reflect the effects of the TCJA or to show cause why no changes in transmission rates were appropriate. DP&L intends to file new transmission rates in response to the show cause order. Because the filing will then be subject to review by the FERC and any interveners, DP&L is unable to determine the impact of the proceeding at this time.

Property, Plant and Equipment (

Property, Plant and Equipment (Notes)	3 Months Ended
	Mar. 31, 2018
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment Disclosure [Text Block]	Property, Plant and Equipment Coal-fired facilities As of March 31, 2018 , DPL , through its subsidiaries, and certain other Ohio utilities had undivided ownership interests in three coal-fired electric generating facilities and numerous transmission facilities. Certain expenses, primarily fuel costs for the generating units, are allocated to the owners based on their energy usage. The remaining expenses, investments in fuel inventory, plant materials and operating supplies, and capital additions are allocated to the owners in accordance with their respective ownership interests. DPL’s share of the operations of such facilities is included within the corresponding line in the Condensed Consolidated Statements of Operations, and DPL’s share of the investment in the facilities is included within Total net property, plant and equipment in the Condensed Consolidated Balance Sheets. Each co-owner provides their own financing for their share of the operations and capital expenditures of the jointly-owned station. DPL's undivided ownership interest in such facilities at March 31, 2018 , was as follows: DPL Share DPL Carrying Value Ownership Summer Production Capacity Gross Plant Accumulated Construction Jointly-owned production units Conesville - Unit 4 16.5 129 $ 0.6 $ 0.6 $ 2.3 Killen - Unit 2 67.0 402 9.5 9.1 — Stuart - Units 2 through 4 35.0 606 1.8 1.8 — Transmission (at varying percentages) 39.4 9.0 — Total 1,137 $ 51.3 $ 20.5 $ 2.3 Each of the above generating units has SCR and FGD equipment installed. In March 2018, AES Ohio Generation completed the sale of its Peaker assets. See Note 14 – Dispositions for more information. AROs We recognize AROs in accordance with GAAP which requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time those obligations are incurred. Upon initial recognition of a legal liability, costs are capitalized as part of the related long-lived asset and depreciated over the useful life of the related asset. Our legal obligations are associated with the retirement of our long-lived assets, consisting primarily of river intake and discharge structures, coal unloading facilities, loading docks, ice breakers and ash disposal facilities. 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 January 1, 2018 $ 131.2 Accretion expense 0.7 Settlements (0.2 ) Reductions due to plant sales (3.4 ) Balance at March 31, 2018 $ 128.3 See Note 5 – Fair Value for further discussion on changes to our AROs.
Subsidiaries [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment Disclosure [Text Block]	Property, Plant and Equipment AROs We recognize AROs in accordance with GAAP which requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time those obligations are incurred. Upon initial recognition of a legal liability, costs are capitalized as part of the related long-lived asset and depreciated over the useful life of the related asset. Our legal obligations are associated with the retirement of our long-lived assets, consisting primarily of river intake and discharge structures, coal unloading facilities, loading docks, ice breakers and ash disposal facilities. Estimating the amount and timing of future expenditures of this type requires significant judgment. Management routinely updates these estimates as additional information becomes available. Changes in the Liability for AROs $ in millions Balance at January 1, 2018 $ 8.0 Revisions to cash flow and timing estimates 0.1 Reductions due to plant sales (3.4 ) Balance at March 31, 2018 $ 4.7 See Note 5 – Fair Value for further discussion on changes to our AROs.

Fair Value

Fair Value	3 Months Ended
	Mar. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value	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 methods exist. The value of our financial instruments represents our best estimates of the fair value, which may not be the value realized in the future. The following table presents the fair value, carrying value and cost of our non-derivative instruments at March 31, 2018 and December 31, 2017 . Information about the fair value of our derivative instruments can be found in Note 6 – Derivative Instruments and Hedging Activities . March 31, 2018 December 31, 2017 $ in millions Cost Fair Value Cost Fair Value Assets Money market funds $ 0.3 $ 0.3 $ 0.3 $ 0.3 Equity securities 2.4 3.8 2.5 4.2 Debt securities 4.3 4.2 4.3 4.3 Hedge funds 0.1 0.2 0.1 0.2 Tangible assets 0.1 0.1 0.1 0.1 Total Assets $ 7.2 $ 8.6 $ 7.3 $ 9.1 Carrying Value Fair Value Carrying Value Fair Value Liabilities Long-term debt (a) $ 1,576.6 $ 1,661.4 $ 1,704.8 $ 1,819.3 (a) Amounts exclude immaterial capital lease obligations at December 31, 2017 These financial instruments are not subject to master netting agreements or collateral requirements and as such are presented in the Condensed Consolidated Balance Sheet at their gross fair value, except for Long-term debt, which is presented at amortized carrying value. Fair Value Hierarchy Fair value is defined as the price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. These inputs are then categorized as: • Level 1 (quoted prices in active markets for identical assets or liabilities); • Level 2 (observable inputs such as quoted prices for similar assets or liabilities or quoted prices in markets that are not active); or • Level 3 (unobservable inputs) reflecting management’s own assumptions about the inputs used in pricing the asset or liability). Valuations of assets and liabilities reflect the value of the instrument including the values associated with counterparty risk. We include our own credit risk and our counterparty’s credit risk in our calculation of fair value using global average default rates based on an annual study conducted by a large rating agency. We did not have any transfers of the fair values of our financial instruments between Level 1, Level 2 or Level 3 of the fair value hierarchy during the three months ended March 31, 2018 or 2017 . 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 Retained Earnings 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 three months ended March 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. DPL had $1.6 million ( $1.0 million after tax) of unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at December 31, 2017 . Long-term 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 long-term debt is presented at cost, net of unamortized premium or discount and unamortized deferred financing costs in the financial statements. The long-term debt amounts include the current portion payable in the next twelve months and have maturities that range from 2019 to 2061 . The fair value of assets and liabilities at March 31, 2018 and December 31, 2017 and the respective category within the fair value hierarchy for DPL is as follows: Assets and Liabilities at Fair Value Level 1 Level 2 Level 3 $ in millions Fair value at March 31, 2018 (a) Based on Quoted Prices in Active Markets Other Observable Inputs Unobservable Inputs Assets Master Trust assets Money market funds $ 0.3 $ 0.3 $ — $ — Equity securities 3.8 — 3.8 — Debt securities 4.2 — 4.2 — Hedge funds 0.2 — 0.2 — Tangible assets 0.1 — 0.1 — Total Master Trust assets 8.6 0.3 8.3 — Derivative assets Interest rate hedges 1.9 — 1.9 — Total Derivative assets 1.9 — 1.9 — Total Assets $ 10.5 $ 0.3 $ 10.2 $ — Liabilities Derivative Liabilities FTRs $ 0.1 $ — $ — $ 0.1 Forward power contracts 0.1 — 0.1 — Total Derivative liabilities 0.2 — 0.1 0.1 Long-term debt 1,661.4 — 1,643.6 17.8 Total Liabilities $ 1,661.6 $ — $ 1,643.7 $ 17.9 (a) Includes credit valuation adjustment Assets and Liabilities at Fair Value Level 1 Level 2 Level 3 $ in millions Fair value at December 31, 2017 (a) Based on Quoted Prices in Active Markets Other Observable Inputs Unobservable Inputs Assets Master Trust assets Money market funds $ 0.3 $ 0.3 $ — $ — Equity securities 4.2 — 4.2 — Debt securities 4.3 — 4.3 — Hedge funds 0.2 — 0.2 — Tangible assets 0.1 — 0.1 — Total Master Trust assets 9.1 0.3 8.8 — Derivative assets Forward power contracts 10.8 — 10.8 — Interest rate hedges 1.8 — 1.8 — Natural gas 0.2 0.2 — — Total Derivative assets 12.8 0.2 12.6 — Total Assets $ 21.9 $ 0.5 $ 21.4 $ — Liabilities Derivative liabilities FTRs $ 0.3 $ — $ — $ 0.3 Natural gas 0.1 0.1 — — Forward power contracts 14.9 — 14.9 — Total Derivative liabilities 15.3 0.1 14.9 0.3 Long-term debt (b) 1,819.3 — 1,801.5 17.8 Total Liabilities $ 1,834.6 $ 0.1 $ 1,816.4 $ 18.1 (a) Includes credit valuation adjustment (b) Amounts exclude immaterial capital lease obligations Our financial instruments are valued using the market approach in the following categories: • Level 1 inputs are used for derivative contracts such as natural gas futures and for money market accounts that are considered cash equivalents. The fair value is determined by reference to quoted market prices and other relevant information generated by market transactions. • Level 2 inputs are used to value derivatives such as forward power contracts (which are traded on the OTC market, but which are valued using prices on the NYMEX for similar contracts on the OTC market). Other Level 2 assets include open-ended mutual funds in the Master Trust, which are valued using the end of day NAV per unit. • Level 3 inputs such as FTRs are considered a Level 3 input because the monthly auctions are considered inactive. Other Level 3 inputs include the credit valuation adjustment on some of the forward power contracts and forward power contracts in less active markets. Our Level 3 inputs are immaterial to our derivative balances as a whole and as such no further disclosures are presented. Approximately 94% 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 is 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 $128.3 million and $131.2 million at March 31, 2018 and December 31, 2017, respectively. On March 17, 2017, the Board of Directors of DP&L approved the retirement of the DP&L operated and co-owned Stuart station coal-fired and diesel-fired generating units and the Killen station coal-fired generating unit and combustion turbine (collectively, the “Facilities”) on or before June 1, 2018, and the co-owners of the Facilities agreed with DP&L to proceed with this plan of retirement. As a result, we performed a long-lived asset impairment analysis during the first quarter of 2017 and determined that the carrying amounts of the Facilities were not recoverable. See Note 15 – Fixed-asset Impairments . 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 Long-lived assets measured at fair value on a non-recurring basis during the periods and their level within the fair value hierarchy: Carrying Fair Value Gross Amount (a) Level 1 Level 2 Level 3 Loss $ in millions Three months ended March 31, 2017 Assets Long-lived assets (b) Stuart $ 42.4 $ — $ — $ 3.3 $ 39.1 Killen $ 35.2 $ — $ — $ 7.9 $ 27.3 Total $ 66.4 (a) Carrying amount at date of valuation (b) See Note 15 – Fixed-asset Impairments for further information The following summarizes the significant unobservable inputs used in the Level 3 measurement on a non-recurring basis during the three months ended March 31, 2017: $ in millions Fair value Valuation technique Unobservable input Weighted average Long-lived assets held and used: Stuart $ 3.3 Discounted cash flow Pre-tax operating margin 10.0 % Weighted-average cost of capital 7.0 % Killen $ 7.9 Discounted cash flow Pre-tax operating margin 22.0 % Weighted-average cost of capital 7.0 %
THE DAYTON POWER AND LIGHT COMPANY [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value	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 methods exist. The value of our financial instruments represents our best estimates of the fair value, which may not be the value realized in the future. The following table presents the fair value, carrying value and cost of our non-derivative instruments at March 31, 2018 and December 31, 2017 . Information about the fair value of our derivative instruments can be found in Note 6 – Derivative Instruments and Hedging Activities . March 31, 2018 December 31, 2017 $ in millions Cost Fair Value Cost Fair Value Assets Money market funds $ 0.3 $ 0.3 $ 0.3 $ 0.3 Equity securities 2.4 3.8 2.5 4.2 Debt securities 4.3 4.2 4.3 4.3 Hedge funds 0.1 0.2 0.1 0.2 Real estate — — — — Tangible assets 0.1 0.1 0.1 0.1 Total assets $ 7.2 $ 8.6 $ 7.3 $ 9.1 Carrying Value Fair Value Carrying Value Fair Value Liabilities Long-term debt $ 587.7 $ 597.2 $ 646.6 $ 658.4 These financial instruments are not subject to master netting agreements or collateral requirements and as such are presented in the Condensed Balance Sheet at their gross fair value, except for Long-term debt, which is presented at amortized carrying value. Fair Value Hierarchy Fair value is defined as the price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. These inputs are then categorized as: • Level 1 (quoted prices in active markets for identical assets or liabilities); • Level 2 (observable inputs such as quoted prices for similar assets or liabilities or quoted prices in markets that are not active); or • Level 3 (unobservable inputs) reflecting management’s own assumptions about the inputs used in pricing the asset or liability). Valuations of assets and liabilities reflect the value of the instrument including the values associated with counterparty risk. We include our own credit risk and our counterparty’s credit risk in our calculation of fair value using global average default rates based on an annual study conducted by a large rating agency. We did not have any transfers of the fair values of our financial instruments between Level 1, Level 2 or Level 3 of the fair value hierarchy during the three months ended March 31, 2018 or 2017 . 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 Retained Earnings 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 three months ended March 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 balance sheets. DP&L had $1.7 million ( $1.1 million after tax) of unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at December 31, 2017 . Long-term 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 long-term debt is presented at cost, net of unamortized premium or discount and unamortized deferred financing costs in the financial statements. The long-term debt amounts include the current portion payable in the next twelve months and have maturities that range from 2020 to 2061 . The fair value of assets and liabilities at March 31, 2018 and December 31, 2017 and the respective category within the fair value hierarchy for DP&L is as follows: Assets and Liabilities at Fair Value Level 1 Level 2 Level 3 $ in millions Fair value at March 31, 2018 (a) Based on Quoted Prices in Active Markets Other Observable Inputs Unobservable Inputs Assets Master Trust assets Money market funds $ 0.3 $ 0.3 $ — $ — Equity securities 3.8 — 3.8 — Debt securities 4.2 — 4.2 — Hedge funds 0.2 — 0.2 — Tangible assets 0.1 — 0.1 — Total Master Trust assets 8.6 0.3 8.3 — Derivative assets Interest rate hedges 1.9 — 1.9 — Total derivative assets 1.9 — 1.9 — Total assets $ 10.5 $ 0.3 $ 10.2 $ — Liabilities Long-term debt $ 597.2 $ — $ 579.4 $ 17.8 Total liabilities $ 597.2 $ — $ 579.4 $ 17.8 (a) Includes credit valuation adjustment Assets and Liabilities at Fair Value Level 1 Level 2 Level 3 $ in millions Fair value at December 31, 2017 (a) Based on Quoted Prices in Active Markets Other Observable Inputs Unobservable Inputs Assets Master Trust assets Money market funds $ 0.3 $ 0.3 $ — $ — Equity securities 4.2 — 4.2 — Debt securities 4.3 — 4.3 — Hedge funds 0.2 — 0.2 — Tangible assets 0.1 — 0.1 — Total Master Trust assets 9.1 0.3 8.8 — Derivative assets Interest rate hedges 1.8 — 1.8 — Total Derivative assets 1.8 — 1.8 — Total assets $ 10.9 $ 0.3 $ 10.6 $ — Liabilities Long-term debt $ 658.4 $ — $ 640.6 $ 17.8 Total liabilities $ 658.4 $ — $ 640.6 $ 17.8 (a) Includes credit valuation adjustment Our financial instruments are valued using the market approach in the following categories: • Level 1 inputs are used for derivative contracts such as natural gas futures and for money market accounts that are considered cash equivalents. The fair value is determined by reference to quoted market prices and other relevant information generated by market transactions. • Level 2 inputs are used to value derivatives such as forward power contracts (which are traded on the OTC market, but which are valued using prices on the NYMEX for similar contracts on the OTC market). Other Level 2 assets include open-ended mutual funds in the Master Trust, which are valued using the end of day NAV per unit. • Level 3 inputs such as FTRs are considered a Level 3 input because the monthly auctions are considered inactive. Other Level 3 inputs include the credit valuation adjustment on some of the forward power contracts and forward power contracts in less active markets. Our Level 3 inputs are immaterial to our derivative balances as a whole and as such no further disclosures are presented. Approximately 100% of the inputs to the fair value of our derivative instruments are from quoted market prices. Our long-term debt is fair valued for disclosure purposes only and most of the fair values are determined using quoted market prices in inactive markets. These fair value inputs are considered Level 2 in the fair value hierarchy. As the Wright-Patterson Air Force Base note is not publicly traded, fair value is assumed to equal carrying value. These fair value inputs are considered Level 3 in the fair value hierarchy as there are no observable inputs. Additional Level 3 disclosures are not presented since our long-term debt is not recorded at fair value. Non-recurring Fair Value Measurements We use the cost approach to determine the fair value of our AROs, which is 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 March 31, 2018 and December 31, 2017, respectively.

Derivative Instruments and Hedg

Derivative Instruments and Hedging Activities	3 Months Ended
	Mar. 31, 2018
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Instruments and Hedging Activities	Derivative Instruments and Hedging Activities In the normal course of business, DPL enters into various financial instruments, including derivative financial instruments. We use derivatives principally to manage the risk of changes in market prices for commodities and interest rate risk associated with our long-term debt. The derivatives that we use to economically hedge these risks are governed by our risk management policies for forward and futures contracts. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The objective of the hedging program is to mitigate financial risks while ensuring that we have adequate resources to meet our requirements. We monitor and value derivative positions monthly as part of our risk management processes. We use published sources for pricing, when possible, to mark positions to market. All of our derivative instruments are used for risk management purposes and are designated as cash flow hedges if they qualify under FASC 815 for accounting purposes. At March 31, 2018 , DPL's derivative instruments were as follows: Commodity Accounting Treatment (a) Unit Purchases Sales Net Purchases/ (Sales) FTRs Not designated MWh 0.1 — 0.1 Forward power contracts Not designated MWh 73.2 — 73.2 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 derivative instruments were as follows: Commodity Accounting Treatment (a) Unit Purchases Sales Net Purchases/ (Sales) FTRs Not designated MWh 2.1 — 2.1 Natural gas futures Not designated Dths 3,322.5 (390.0 ) 2,932.5 Forward power contracts Designated MWh 678.5 (1,667.0 ) (988.5 ) Forward power contracts Not designated MWh 871.0 (765.6 ) 105.4 Interest rate swaps Designated USD $ 200,000.0 $ — $ 200,000.0 (a) Refers to whether the derivative instruments have been designated as a cash flow hedge. Cash Flow Hedges As part of our risk management processes, we identify the relationships between hedging instruments and hedged items, as well as the risk management objective and strategy for undertaking various hedge transactions. The fair values of cash flow hedges determined by current public market prices will continue to fluctuate with changes in market prices up to contract expiration. The effective portion of the hedging transaction is recognized in AOCI and transferred to earnings using specific identification of each contract when the forecasted hedged transaction takes place or when the forecasted hedged transaction is probable of not occurring. The ineffective portion of the cash flow hedge is recognized in earnings in the current period. All risk components were taken into account to determine the hedge effectiveness of the cash flow hedges. We enter into forward power contracts to manage commodity price risk exposure related to our generation of electricity. We do not hedge all commodity price risk. We reclassify gains and losses on forward power contracts from AOCI into earnings in those periods in which the contracts settle. As of March 31, 2018, 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. 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. 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 million of these interest rate swaps due to the partial re-payment 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 had previously entered into interest rate derivative contracts to manage interest rate exposure related to anticipated borrowings of fixed-rate debt. These interest rate derivative contracts were settled in the third quarter of 2013 and we continue to amortize amounts out of AOCI into interest expense. The following tables provide information concerning gains or losses recognized in AOCI for the cash flow hedges for the three months ended March 31, 2018 and 2017 : Three months ended Three months ended March 31, 2018 March 31, 2017 Interest Interest $ in millions (net of tax) Power Rate Hedge Power Rate Hedge Beginning accumulated derivative gains / (losses) in AOCI $ (2.8 ) $ 17.5 $ (4.3 ) $ 17.4 Net gains associated with current period hedging transactions — 0.9 4.9 0.3 Net gains / (losses) reclassified to earnings Interest expense — (0.4 ) — (0.2 ) Revenues 4.1 — (0.9 ) — Purchased power (1.4 ) — 2.1 — Ending accumulated derivative gains / (losses) in AOCI $ (0.1 ) $ 18.0 $ 1.8 $ 17.5 Portion expected to be reclassified to earnings in the next twelve months (a) $ — $ (0.4 ) Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) 0 29 (a) The actual amounts that we reclassify from AOCI to earnings related to power can differ from the estimate above due to market price changes. Net gains or losses associated with the ineffective portion of the hedging transactions were immaterial in the periods presented. Derivatives not designated as hedges Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for hedge accounting or the normal purchase and normal sales scope exceptions under FASC 815. Accordingly, such contracts are recorded at fair value with changes in the fair value charged or credited to the Condensed Consolidated Statements of Operations in the period in which the change occurred. This is commonly referred to as “MTM accounting". Contracts we enter into as part of our risk management program may be settled financially, by physical delivery, or net settled with the counterparty. FTRs, natural gas futures, and certain forward power contracts are currently marked to market. Certain qualifying derivative instruments have been designated as normal purchase or normal sale 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 and are recognized in the Condensed Consolidated Statements of Operations on an accrual basis. Financial Statement Effect The following tables present the amount and classification within the Condensed Consolidated Statements of Operations of the gains and losses on DPL’s derivatives not designated as hedging instruments for the three months ended March 31, 2018 and 2017 : For the three months ended March 31, 2018 $ in millions FTRs Power Natural Gas Total Change in unrealized gain / (loss) $ 0.2 $ (0.1 ) $ (0.1 ) $ — Realized gain / (loss) 0.2 (0.2 ) 0.2 0.2 Total $ 0.4 $ (0.3 ) $ 0.1 $ 0.2 Recorded in Income Statement: gain / (loss) Revenues $ — $ (1.5 ) $ — $ (1.5 ) Purchased power 0.4 1.2 0.1 1.7 Total $ 0.4 $ (0.3 ) $ 0.1 $ 0.2 For the three months ended March 31, 2017 $ in millions FTRs Power Natural Gas Total Change in unrealized gain / (loss) $ — $ (0.1 ) $ (0.1 ) $ (0.2 ) Realized gain / (loss) 0.2 (2.6 ) (0.2 ) (2.6 ) Total $ 0.2 $ (2.7 ) $ (0.3 ) $ (2.8 ) Recorded in Income Statement: gain / (loss) Revenues $ — $ (6.7 ) $ — $ (6.7 ) Purchased power 0.2 4.0 (0.3 ) 3.9 Total $ 0.2 $ (2.7 ) $ (0.3 ) $ (2.8 ) 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 at March 31, 2018 Gross Amounts Not Offset in the Condensed 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 Fair Value Assets Short-term derivative positions (presented in Other prepayments and current assets) Interest rate swap Designated $ 0.5 $ — $ — $ 0.5 Long-term derivative positions (presented in Other deferred assets) Interest rate swap Designated 1.4 — — 1.4 Total assets $ 1.9 $ — $ — $ 1.9 Liabilities Short-term derivative positions (presented in Other current liabilities) Forward power contracts Not designated 0.1 — (0.1 ) — FTRs Not designated 0.1 — — 0.1 Total liabilities $ 0.2 $ — $ (0.1 ) $ 0.1 (a) includes credit valuation adjustment Fair Values of Derivative Instruments at December 31, 2017 Gross Amounts Not Offset in the Condensed 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 Fair Value Assets Short-term derivative positions (presented in Other prepayments and current assets) 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 1.8 — — 1.8 Forward power contracts Not designated 0.6 — — 0.6 Total assets $ 12.8 $ (8.7 ) $ — $ 4.1 Liabilities Short-term derivative positions (presented in Other current liabilities) Forward power contracts Designated $ 9.0 $ (4.9 ) $ (1.4 ) $ 2.7 Forward power contracts Not designated 5.9 (3.7 ) — 2.2 FTRs Not designated 0.3 — — 0.3 Natural gas Not designated 0.1 (0.1 ) — — Total liabilities $ 15.3 $ (8.7 ) $ (1.4 ) $ 5.2 (a) includes credit valuation adjustment Credit risk-related contingent features Most of DPL’s commodity derivatives (except FTRs) are transacted through a broker account which is fully-collateralized, while FTRs are collateralized through the PJM Market. Therefore, no further collateral would need to be posted due to any changes in DPL’s credit ratings.
THE DAYTON POWER AND LIGHT COMPANY [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Instruments and Hedging Activities	Derivative Instruments and Hedging Activities In the normal course of business, DP&L enters into various financial instruments, including derivative financial instruments. We use derivatives principally to manage the risk of changes in market prices for commodities and interest rate risk associated with our long-term debt. The derivatives that we use to economically hedge these risks are governed by our risk management policies for forward and futures contracts. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The objective of the hedging program is to mitigate financial risks while ensuring that we have adequate resources to meet our requirements. We monitor and value derivative positions monthly as part of our risk management processes. We use published sources for pricing, when possible, to mark positions to market. All of our derivative instruments are used for risk management purposes and are designated as cash flow hedges if they qualify under FASC 815 for accounting purposes. DP&L's interest rate swaps are designated as a cash flow hedge. Cash Flow Hedges As part of our risk management processes, we identify the relationships between hedging instruments and hedged items, as well as the risk management objective and strategy for undertaking various hedge transactions. The fair values of cash flow hedges determined by current public market prices will continue to fluctuate with changes in market prices up to contract expiration. The effective portion of the hedging transaction is recognized in AOCI and transferred to earnings using specific identification of each contract when the forecasted hedged transaction takes place or when the forecasted hedged transaction is probable of not occurring. The ineffective portion of the cash flow hedge is recognized in earnings in the current period. All risk components were taken into account to determine the hedge effectiveness of the cash flow hedges. As of March 31, 2018, 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. 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. 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 re-payment 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. The following tables provide information concerning gains or losses recognized in AOCI for the cash flow hedges for the three months ended March 31, 2018 and 2017 : Three months ended Three months ended March 31, 2018 March 31, 2017 Interest Interest $ in millions (net of tax) Power Rate Hedge Power Rate Hedge Beginning accumulated derivative gains / (losses) in AOCI $ — $ 1.4 $ (4.3 ) $ 1.6 Net gains associated with current period hedging transactions — 0.5 — 0.3 Net gains / (losses) reclassified to earnings Interest expense — (0.3 ) — (0.2 ) Loss from discontinued operations — — 6.1 — Ending accumulated derivative gains in AOCI $ — $ 1.6 $ 1.8 $ 1.7 Portion expected to be reclassified to earnings in the next twelve months (a) $ — $ (0.3 ) Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) 0 29 (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. Financial Statement Effect 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: Hedging Designation Balance sheet classification March 31, 2018 December 31, 2017 Interest Rate Hedges in an Asset Position Cash Flow Hedge Other Deferred Assets Gross Fair Value as presented in the Balance Sheets $ 1.9 $ 1.8 Any ineffectiveness on the interest rate hedges and the monthly settlement of the interest rate hedges is recorded in interest expense within the Condensed Statements of Operations.

Debt Obligations

Debt Obligations	3 Months Ended
	Mar. 31, 2018
Debt Instrument [Line Items]
Debt Obligations	Long-term Debt The following table summarizes DPL's outstanding long-term debt. Interest March 31, December 31, $ in millions Rate Maturity 2018 2017 Term loan - rates from 3.57% - 4.82% (a) and 4.01% - 4.60% (b) 2022 $ 439.4 $ 440.6 Tax-exempt First Mortgage Bonds - rates from 2.50% - 2.58% (a) and 1.52% - 1.92% (b) 2020 140.0 200.0 U.S. Government note 4.2% 2061 17.8 17.8 Unamortized deferred financing costs (7.8 ) (9.8 ) Unamortized long-term debt discounts and premiums, net (1.7 ) (2.0 ) Total long-term debt at consolidated subsidiary 587.7 646.6 Bank term loan - rates from 3.82% - 3.90% (a) and 3.02% - 4.10% (b) 2020 — 70.0 Senior unsecured notes 6.75% 2019 200.0 200.0 Senior unsecured notes 7.25% 2021 780.0 780.0 Note to DPL Capital Trust II (c) 8.125% 2031 15.6 15.6 Capital leases — 0.2 Unamortized deferred financing costs (6.2 ) (6.8 ) Unamortized long-term debt discounts and premiums, net (0.5 ) (0.5 ) Total long-term debt 1,576.6 1,705.1 Less: current portion (105.6 ) (4.7 ) Long-term debt, net of current portion $ 1,471.0 $ 1,700.4 (a) Range of interest rates for the three months ended March 31, 2018 . (b) Range of interest rates for the year ended December 31, 2017 . (c) Note payable to related party. Deferred financing costs are amortized over the remaining life of the debt using the effective interest method. Premiums or discounts on long-term debt are amortized over the remaining life of the debt using the effective interest method. Line of credit At March 31, 2018 , DPL had no outstanding borrowings on its line of credit. In addition, DP&L had $20.0 million in outstanding borrowings on its line of credit. 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, which were classified as current at March 31, 2018, 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). On March 30, 2018, DP&L notified the Trustee of the same First Mortgage Bonds that DP&L was going to call at par value (plus accrued and unpaid interest) $60.0 million of these bonds. As of March 31, 2018, $60.0 million of these bonds were defeased. On March 27, 2018, DPL made a $70.0 million prepayment to eliminate the outstanding balance of its 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) modified a "call protection" provision which as modified 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. Long-term 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. The second financial covenant measures EBITDA to Interest Expense. The EBITDA to Interest Expense ratio is calculated, at the end of each fiscal quarter, by dividing consolidated EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period. DPL’s revolving credit agreement has two financial covenants. The first financial covenant, a Total Debt to EBITDA ratio, is calculated at the end of each fiscal quarter by dividing total debt at the end of the current quarter by consolidated EBITDA for the four prior fiscal quarters. The second financial covenant is an EBITDA to Interest Expense ratio that is calculated, at the end of each fiscal quarter, by dividing EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period. DP&L does not have any meaningful restrictions in its debt financing documents prohibiting dividends to its parent, DPL . DPL’s secured revolving credit agreement and senior unsecured notes due 2019 restrict dividend payments from DPL to AES, such that DPL cannot make dividend payments unless at the time of, and/or as a result of the distribution, (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 March 31, 2018, DPL’s leverage ratio was at 1.47 to 1.00. As a result, as of March 31, 2018, DPL was prohibited under each of these agreements from making a distribution to its shareholder or making a loan to any of its affiliates (other than its subsidiaries). DPL is also restricted from making dividend and tax sharing payments from DPL to AES per its 2017 ESP. This order restricts dividend payments from DPL to AES during the term of the 2017 ESP and restricts tax sharing payments from DPL to AES during the term of the DMR. DP&L's Total Consolidated EBITDA to Consolidated Interest Charges shall not be less than 2.50 to 1.00. In addition, DP&L’s Total Debt to Total Capitalization ratio shall not be greater than 0.65 to 1.00. Except that, after Generation Separation and the twelve-month period following (October 1, 2017 to September 30, 2018) the ratio shall be a) increased to 0.75 to 1.00 or b) 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. The Total Debt to Capitalization covenant is calculated as the sum of DP&L’s current and long-term portion of debt, divided by the total of DP&L’s net worth and total debt. The cost of borrowing under DPL's revolving credit agreement adjust under certain credit rating scenarios. DPL’s revolving credit agreement and senior unsecured notes due 2019 restrict dividend payments from DPL to AES. As of March 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.
THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Debt Obligations	Long-term Debt The following table summarizes DP&L's outstanding long-term debt. Interest March 31, December 31, $ in millions Rate Maturity 2018 2017 Term loan - rates from 3.57% - 4.82% (a) and 4.01% - 4.60% (b) 2022 $ 439.4 $ 440.6 Tax-exempt First Mortgage Bonds - rates from 2.50% - 2.58% (a) and 1.52% - 1.92% (b) 2020 140.0 200.0 U.S. Government note 4.2% 2061 17.8 17.8 Unamortized deferred financing costs (7.8 ) (9.8 ) Unamortized long-term debt discounts (1.7 ) (2.0 ) Total long-term debt 587.7 646.6 Less: current portion (4.6 ) (4.6 ) Long-term debt, net of current portion $ 583.1 $ 642.0 (a) Range of interest rates for the three months ended March 31, 2018 . (b) Range of interest rates for the year ended December 31, 2017 . Deferred financing costs are amortized over the remaining life of the debt using the effective interest method. Premiums or discounts on long-term debt are amortized over the remaining life of the debt using the effective interest method. Line of credit At March 31, 2018 , DP&L had $20.0 million in outstanding borrowings on its line of credit. Significant transactions 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). On March 30, 2018, DP&L notified the Trustee of the same First Mortgage Bonds that DP&L was going to call at par value (plus accrued and unpaid interest) $60.0 million of these bonds. As of March 31, 2018, $60.0 million of these bonds were defeased. 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) modified a "call protection" provision which as modified 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. Long-term 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. The second financial covenant measures EBITDA to Interest Expense. The EBITDA to Interest Expense ratio is calculated, at the end of each fiscal quarter, by dividing consolidated EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period. DP&L's Total Consolidated EBITDA to Consolidated Interest Charges shall not be less than 2.50 to 1.00. In addition, DP&L’s Total Debt to Total Capitalization ratio shall not be greater than 0.65 to 1.00. Except that, after Generation Separation and the twelve-month period following (October 1, 2017 to September 30, 2018) the ratio shall be a) increased to 0.75 to 1.00 or b) 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. The Total Debt to Capitalization covenant is calculated as the sum of DP&L’s current and long-term portion of debt, divided by the total of DP&L’s net worth and total debt. As of March 31, 2018 , DP&L was in compliance with all debt covenants, including the financial covenants described above. DP&L does not have any meaningful restrictions in its debt financing documents prohibiting dividends to its parent, DPL . Substantially all property, plant & equipment of DP&L is subject to the lien of the mortgage securing DP&L’s First and Refunding Mortgage.

Income Taxes

Income Taxes	3 Months Ended
	Mar. 31, 2018
Entity Information [Line Items]
Income Taxes	Income Taxes The following table details the effective tax rates for the three months ended March 31, 2018 and 2017 . Three months ended March 31, 2018 2017 DPL 17.6% 37.9% Income tax expense for the three months ended March 31, 2018 and 2017 was calculated using the estimated annual effective income tax rates for 2018 and 2017 of 19.2% and 37.6% , respectively. Management estimates the annual effective tax rate based on its forecast of annual pre-tax income. To the extent that actual pre-tax results for the year differ from the forecasts applied to the most recent interim period, the estimated rates could be materially different from the actual effective tax rates. The decrease in the estimated annual effective rate compared to the same period in 2017 is primarily due to the effects of the TCJA. The primary impact of the TCJA was lowering of the statutory corporate income tax rate to 21% from 35% effective January 1, 2018. The rate was further decreased by the change in estimated flow-through depreciation. These decreases were partially offset by the repeal of the manufacturer’s production deduction For the three months ended March 31, 2018, DPL’s current period effective tax rate was lower than the estimated annual effective rate primarily due to discrete tax items relating to the Beckjord Facility and Peaker Assets transactions (see Note 14 – Dispositions ). Per the terms of 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. As such, during the first quarter of 2018 we converted $45.1 million of accrued tax sharing liabilities with AES to additional equity investment in DPL .
THE DAYTON POWER AND LIGHT COMPANY [Member]
Entity Information [Line Items]
Income Taxes	Income Taxes The following table details the effective tax rates for the three months ended March 31, 2018 and 2017 . Three months ended March 31, 2018 2017 DP&L 18.7% 32.0% Income tax expense for the three months ended March 31, 2018 and 2017 was calculated using the estimated annual effective income tax rates for 2018 and 2017 of 19.8% and 33.8% , respectively. Management estimates the annual effective tax rate based on its forecast of annual pre-tax income. To the extent that actual pre-tax results for the year differ from the forecasts applied to the most recent interim period, the estimated rates could be materially different from the actual effective tax rates. The decrease in the estimated annual effective rate compared to the same period in 2017 is primarily due to the effects of the TCJA. The primary impact of the TCJA was lowering of the statutory corporate income tax rate to 21% from 35% effective January 1, 2018. The rate was further decreased by the change in estimated flow-through depreciation. These decreases were partially offset by the repeal of the manufacturer’s production deduction For the three months ended March 31, 2018, DP&L’s current period effective tax rate was lower than the estimated annual effective rate primarily due to discrete tax items relating to the Beckjord Facility transaction (see Note 14 – Dispositions ).

Benefit Plans

Benefit Plans	3 Months Ended
	Mar. 31, 2018
Entity Information [Line Items]
Pension and Postretirement Benefits	Benefit Plans DP&L sponsors a defined benefit pension plan for the majority of its employees. We generally fund pension plan benefits as accrued in accordance with the minimum funding requirements of ERISA and, in addition, make voluntary contributions from time to time. There were $7.6 million in employer contributions during the three months ended March 31, 2018 and $5.0 million during the three months ended March 31, 2017. The amounts presented in the following tables for pension include the collective bargaining plan formula, the traditional management plan formula, the cash balance plan formula and the SERP, in the aggregate. The pension costs below have not been adjusted for amounts billed to the Service Company for former DP&L employees who are now employed by the Service Company that are still participants in the DP&L plan. The net periodic benefit cost of the pension benefit plans for the three months ended March 31, 2018 and 2017 was: Three months ended March 31, $ in millions 2018 2017 Service cost $ 1.5 $ 1.4 Interest cost 3.4 3.6 Expected return on plan assets (5.2 ) (5.7 ) Plan curtailment (a) — 4.1 Amortization of unrecognized: Prior service cost 0.2 0.4 Actuarial loss 1.6 1.3 Net periodic benefit cost $ 1.5 $ 5.1 (a) As a result of the decision to retire certain of DP&L's coal-fired plants, we recognized a plan curtailment of $4.1 million in the first quarter of 2017. See Note 15 – Fixed-asset Impairments for more information. In addition, DP&L provides postretirement health care and life insurance benefits to certain retired employees, their spouses and eligible dependents. We have funded a portion of the union-eligible benefits using a Voluntary Employee Beneficiary Association Trust. These postretirement health care benefits and the related unfunded obligation of $12.7 million at both March 31, 2018 and December 31, 2017 were not material to the financial statements in the periods covered by this report. Benefit payments, which reflect future service, are estimated to be paid as follows: $ in millions Estimated balance to be paid during Pension 2018 $ 21.3 2019 $ 28.2 2020 $ 27.9 2021 $ 27.6 2022 $ 27.3 2023 - 2027 $ 131.3
THE DAYTON POWER AND LIGHT COMPANY [Member]
Entity Information [Line Items]
Pension and Postretirement Benefits	Benefit Plans DP&L sponsors a defined benefit pension plan for the majority of its employees. We generally fund pension plan benefits as accrued in accordance with the minimum funding requirements of ERISA and, in addition, make voluntary contributions from time to time. There were $7.6 million in employer contributions during the three months ended March 31, 2018 and $5.0 million during the three months ended March 31, 2017. The amounts presented in the following tables for pension include the collective bargaining plan formula, the traditional management plan formula, the cash balance plan formula and the SERP, in the aggregate. The pension costs below have not been adjusted for amounts billed to the Service Company for former DP&L employees who are now employed by the Service Company or for amounts billed to AES Ohio Generation for employees employed by AES Ohio Generation that are still participants in the DP&L plan. The net periodic benefit cost of the pension benefit plans for the three months ended March 31, 2018 and 2017 was: Three months ended March 31, $ in millions 2018 2017 Service cost $ 1.5 $ 1.4 Interest cost 3.4 3.6 Expected return on plan assets (5.2 ) (5.7 ) Plan curtailment (a) — 5.6 Amortization of unrecognized: Prior service cost 0.4 0.5 Actuarial loss 2.3 2.2 Net periodic benefit cost $ 2.4 $ 7.6 (a) As a result of the decision to retire certain of DP&L's coal-fired plants, we recognized a plan curtailment of $5.6 million in the first quarter of 2017. In addition, DP&L provides postretirement health care and life insurance benefits to certain retired employees, their spouses and eligible dependents. We have funded a portion of the union-eligible benefits using a Voluntary Employee Beneficiary Association Trust. These postretirement health care benefits and the related unfunded obligation of $12.7 million at both March 31, 2018 and December 31, 2017 were not material to the financial statements in the periods covered by this report. Benefit payments, which reflect future service, are estimated to be paid as follows: $ in millions Estimated balance to be paid during Pension 2018 $ 21.3 2019 $ 28.2 2020 $ 27.9 2021 $ 27.6 2022 $ 27.3 2023 - 2027 $ 131.3

Shareholder's Equity

Shareholder's Equity	3 Months Ended
	Mar. 31, 2018
Class of Stock [Line Items]
Shareholder's Equity	Shareholder's Equity 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 . For the three months ended March 31, 2018 , AES made non-cash capital contributions of $45.1 million and waived the amount owed to it by DPL related to tax-sharing payments for current tax liabilities.
THE DAYTON POWER AND LIGHT COMPANY [Member]
Class of Stock [Line Items]
Shareholder's Equity	Shareholder’s Equity DP&L has 250,000,000 authorized shares of common stock, $0.01 par value, of which 41,172,173 are outstanding at March 31, 2018 . All common shares are held by DP&L’s parent, DPL . As part of the PUCO’s approval of the Merger, DP&L agreed to maintain a capital structure that includes an equity ratio, calculated as total equity divided by total capitalization, of at least 50 percent and to not have a negative retained earnings balance. As of March 31, 2018 , DP&L's equity ratio was 39% and retained earnings balance was negative. It is unknown what impact, if any, this will have on DP&L . In the generation separation order dated September 17, 2014, the PUCO permitted DP&L to temporarily maintain long-term debt of $750.0 million or 75% of its rate base, whichever is greater, until January 1, 2018. After considering the payments and defeasance noted in Note 7 – Long-term Debt , DP&L's long-term debt is $597.2 million . 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 $23.8 million to DPL . In the first quarter of 2017 , DP&L made returns of capital payments of $9.0 million to DPL .

Contractual Obligations, Commer

Contractual Obligations, Commercial Commitments and Contingencies	3 Months Ended
	Mar. 31, 2018
Entity Information [Line Items]
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 March 31, 2018 , DPL had $36.7 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 select present and future obligations of AES Ohio Generation to such beneficiaries and are terminable by DPL upon written notice to the beneficiaries within a certain time. The carrying amount of obligations for commercial transactions covered by these guarantees recorded in our Condensed Consolidated Balance Sheets was $1.4 million and $0.9 million at March 31, 2018 and December 31, 2017 , respectively. To date, DPL has not incurred any losses related to the guarantees of AES Ohio Generation ’s obligations 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 March 31, 2018 , DP&L could be responsible for the repayment of 4.9% , or $70.1 million , of a $1,430.6 million debt obligation comprised of both fixed and variable rate securities with maturities from 2019 to 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. As of March 31, 2018 , we have no knowledge of such a default. Commercial Commitments and Contractual Obligations There have been no material changes, outside the ordinary course of business, to our commercial commitments and to the information disclosed in the contractual obligations table in our Form 10-K for the fiscal year ended December 31, 2017 . Contingencies In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under various laws and regulations. We believe the amounts provided in our Condensed Consolidated Financial Statements, as prescribed by GAAP, are adequate considering 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 discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our Condensed Consolidated Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided as of March 31, 2018 , cannot be reasonably determined. Environmental Matters DPL’s and DP&L’s facilities and operations are subject to a wide range of federal, state and local environmental regulations and laws. The environmental issues that may affect us include: • The federal CAA and state laws and regulations (including State Implementation Plans) 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 climate change; • Rules and future rules issued by the USEPA, the Ohio EPA or other authorities that require or will require substantial reductions in SO 2 , particulates, mercury, acid gases, NOx, and other air emissions. DPL has installed emission control technology and is taking other measures to comply with required and anticipated reductions; • Rules and future rules issued by the USEPA, 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 consists of fly ash and other coal combustion by-products. In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. In the normal course of business, we have investigatory and remedial activities underway at our facilities to comply, or to determine compliance, with such regulations. We record liabilities for loss contingencies related to environmental matters when a loss is probable of occurring and can be reasonably estimated in accordance with the provisions of GAAP. Accordingly, we have immaterial accruals for loss contingencies for environmental matters. We also have a number of environmental matters for which we have not accrued loss contingencies because the risk of loss is not probable, or a loss cannot be reasonably estimated. We evaluate the potential liability related to environmental matters quarterly and may revise our estimates. Such revisions in the estimates of the potential liabilities could have a material adverse effect on our results of operations, financial condition or cash flows. We have several pending environmental matters associated with our coal-fired generation units. Some of these matters could have material adverse impacts on the operation of the power stations.
THE DAYTON POWER AND LIGHT COMPANY [Member]
Entity Information [Line Items]
Contractual Obligations, Commercial Commitments and Contingencies	Contractual Obligations, Commercial Commitments and Contingencies 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 March 31, 2018 , DP&L could be responsible for the repayment of 4.9% , or $70.1 million , of a $1,430.6 million debt obligation comprised of both fixed and variable rate securities with maturities from 2019 to 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. As of March 31, 2018 , we have no knowledge of such a default. Commercial Commitments and Contractual Obligations There have been no material changes, outside the ordinary course of business, to our commercial commitments and to the information disclosed in the contractual obligations table in our Form 10-K for the fiscal year ended December 31, 2017 . Contingencies In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under various laws and regulations. We believe the amounts provided in our Condensed Financial Statements, as prescribed by GAAP, are adequate considering 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 discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our Condensed Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided as of March 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 regulations and laws. The environmental issues that may affect us include: • The federal CAA and state laws and regulations (including State Implementation Plans) which require compliance, obtaining permits and reporting as to air emissions; • Rules and future rules issued by the USEPA, the Ohio EPA or other authorities that require or will require reporting and reductions of GHGs; • Rules and future rules issued by the USEPA, the Ohio EPA or other authorities associated with the federal Clean Water Act, which prohibits the discharge of pollutants into waters of the United States except pursuant to appropriate permits; and • Solid and hazardous waste laws and regulations, which govern the management and disposal of certain waste. In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. In the normal course of business, we have investigatory and remedial activities underway at our facilities to comply, or to determine compliance, with such regulations. We record liabilities for loss contingencies related to environmental matters when a loss is probable of occurring and can be reasonably estimated in accordance with the provisions of GAAP. Accordingly, we have immaterial accruals for loss contingencies for environmental matters. We also have a number of environmental matters for which we have not accrued loss contingencies because the risk of loss is not probable, or a loss cannot be reasonably estimated. We evaluate the potential liability related to environmental matters quarterly and may revise our estimates. Such revisions in the estimates of the potential liabilities could have a material adverse effect on our results of operations, financial condition or cash flows. We have several pending environmental matters associated with our coal-fired generation units. Some of these matters could have material adverse impacts on the operation of the power stations.

Business Segments

Business Segments	3 Months Ended
	Mar. 31, 2018
Segment Reporting Information [Line Items]
Business Segments	Business Segments DPL currently manages its business through two reportable operating segments, the T&D segment and the Generation segment. The primary segment performance measure is income / (loss) from continuing operations before income tax as management has concluded that this measure best reflects the underlying business performance of DPL and is the most relevant measure considered in DPL’s internal evaluation of the financial performance of its segments. The segments are discussed further below: Transmission and Distribution Segment The T&D segment is comprised primarily of DP&L’s electric transmission and distribution businesses, which distribute electricity to residential, commercial, industrial and governmental customers. DP&L distributes electricity to more than 523,000 retail customers 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 recording regulatory assets when incurred costs are expected to be recovered in future customer rates and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs. The T&D segment includes revenues and costs associated with our investment in OVEC and the historical results of DP&L’s Beckjord Facility, which was closed in 2014 and transferred to a third party in the first quarter of 2018, and Hutchings Coal, which was closed in 2013. As these assets did not transfer to AES Ohio Generation as part of DP&L's Generation Separation on October 1, 2017, they are grouped with the T&D assets for segment reporting purposes. In addition, regulatory deferrals and collections, which include fuel deferrals in historical periods, are included in the T&D segment. Generation Segment The Generation segment is comprised of AES Ohio Generation's electric generation business. Prior to October 1, 2017, AES Ohio Generation owned and operated peaking generating facilities, and DP&L owned multiple coal-fired and peaking electric generating facilities. As a result of Generation Separation on October 1, 2017, the DP&L -owned generating facilities were transferred to AES Ohio Generation. On March 27, 2018, after receipt of all necessary regulatory approvals, AES Ohio Generation sold its peaking generating facilities, including those that it had obtained from DP&L as described above. As a result of this transaction, AES Ohio Generation’s remaining generation fleet consists of ownership interests in the Stuart generating station 2-4 and diesels, Killen Unit 2 and combustion turbine and Conesville Unit 4. For more information on this transaction, see Note 14 – Dispositions . AES Ohio Generation sells all of its generated energy and capacity into the PJM wholesale market. 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. 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, costs of sales and expenses are eliminated in consolidation. Certain shared and corporate costs are allocated among reporting segments. The following tables present financial information for each of DPL’s reportable business segments: $ in millions T&D Generation (a) Other (a) Adjustments and Eliminations DPL Consolidated Three months ended March 31, 2018 Revenues from external customers $ 195.8 $ 95.0 $ 2.4 $ — $ 293.2 Intersegment revenues 0.2 — 0.6 (0.8 ) — Total revenues $ 196.0 $ 95.0 $ 3.0 $ (0.8 ) $ 293.2 Depreciation and amortization $ 18.6 $ 1.5 $ — $ — $ 20.1 Fixed-asset Impairments (Note 15) $ — $ — $ — $ — $ — Interest expense $ 8.2 $ — $ 19.8 $ — $ 28.0 Income / (loss) from continuing operations before income tax $ 19.3 $ 71.0 $ (69.8 ) $ — $ 20.5 Cash capital expenditures $ 24.6 $ 1.7 $ 1.0 $ — $ 27.3 At March 31, 2018 Total assets $ 1,666.9 $ 228.9 $ 580.4 $ (580.9 ) $ 1,895.3 (a) During the three months ended March 31, 2018, the Generation segment recorded a gain on the sale of the Peaker assets of $52.5 million, and the Other segment recorded a loss on the sale of the Peaker assets of $54.4 million, due to the asset values established by applying purchase accounting. These gains / (losses) resulted in a consolidated DPL loss on the sale of the Peaker assets of $1.9 million and are included in Income / (loss) from continuing operations before income tax. $ in millions T&D Generation Other Adjustments and Eliminations DPL Consolidated Three months ended March 31, 2017 Revenues from external customers $ 189.8 $ 131.8 $ 2.3 $ — $ 323.9 Intersegment revenues 0.3 — 1.4 (1.7 ) — Total revenues $ 190.1 $ 131.8 $ 3.7 $ (1.7 ) $ 323.9 Depreciation and amortization $ 18.1 $ 7.0 $ 2.9 $ — $ 28.0 Fixed-asset Impairments (Note 15) $ — $ 66.3 $ 0.1 $ — $ 66.4 Interest expense $ 7.6 $ — $ 19.8 $ (0.1 ) $ 27.3 Income / (loss) from continuing operations before income tax $ 25.0 $ (86.8 ) $ (21.4 ) $ — $ (83.2 ) Cash capital expenditures $ 26.3 $ 14.1 $ 1.0 $ — $ 41.4 At December 31, 2017 Total assets $ 1,689.4 $ 275.0 $ 468.0 $ (383.2 ) $ 2,049.2

Revenue (Notes)

Revenue (Notes)	3 Months Ended
	Mar. 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 at the generation stations is sold to an RTO, and these are classified as Wholesale revenues. Wholesale revenues also includes the gains or losses on derivatives associated with the sale of electricity. In PJM, the promise to sell energy is separately identifiable from participation in the capacity market and the two products can be transacted independently of one another. As such, wholesale revenues have 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 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 $290.3 million for the three months ended March 31, 2018 . The following table presents our revenue from contracts with customers and other revenue by segment during the period ended March 31, 2018 : $ in millions T&D Generation Other Adjustments and Eliminations Total Retail Revenue Retail revenue from contracts with customers $ 161.2 $ — $ — $ (0.2 ) $ 161.0 Other retail revenues (a) 9.2 — — — — — 9.2 Wholesale Revenue Wholesale revenue from contracts with customers 12.6 72.2 — — 84.8 Derivative losses (b) — (6.3 ) — — (6.3 ) RTO revenue 11.1 1.8 — — 12.9 RTO capacity revenues 1.9 27.3 — — 29.2 Other revenues from contracts with customers (c) — — 2.4 — 2.4 Other revenues — — 0.6 (0.6 ) — Total revenues $ 196.0 $ 95.0 $ 3.0 $ (0.8 ) $ 293.2 (a) Other retail revenue primarily includes alternative revenue programs not accounted for under ASC 606. Accounts receivable balances associated with these revenues were $3.1 million as of March 31, 2018 . (b) Derivative gains and losses are not accounted for under ASC 606. As of March 31, 2018 , accounts receivable balances associated with derivatives were $1.7 million . (c) 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 $73.0 million and $79.4 million as of March 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 ASC 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.
Subsidiaries [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 an RTO, and these are classified as Wholesale revenues. Wholesale revenues also includes the gains or losses on derivatives associated with the sale of electricity. In PJM, the promise to sell energy is separately identifiable from participation in the capacity market and the two products can be transacted independently of one another. As such, wholesale revenues have 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 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. 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 $186.8 million for the three months ended March 31, 2018 . The following table presents our revenue from contracts with customers and other revenue during the period ended March 31, 2018 : $ in millions DP&L Total Retail Revenue Retail revenue from contracts with customers $ 161.2 Other retail revenues (a) 9.2 Wholesale Revenue Wholesale revenue from contracts with customers 12.6 RTO revenue 11.1 RTO capacity revenues 1.9 Total revenues $ 196.0 (a) Other retail revenue primarily includes alternative revenue programs not accounted for under ASC 606. Accounts receivable balances associated with these revenues were $3.1 million as of March 31, 2018 . The balances of receivables from contracts with customers were $58.8 million and $62.1 million as of March 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 ASC 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.

Dispositions (Notes)

Dispositions (Notes)	3 Months Ended
	Mar. 31, 2018
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Discontinued Operations	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 three months ended March 31, 2018 and 2017. Prior to the transfer, the Beckjord Facility was included in the T&D segment. Peaker Assets – On March 27, 2018, DPL and AES Ohio Generation completed the sale transaction of the Peaker assets to Kimura Power, LLC for total proceeds of $239.3 million , which will be subject to a customary post-closing reconciliation. This transaction resulted in a loss on sale of $1.9 million for the three months ended March 31, 2018. Prior to the sale, the Peaker assets were included in the Generation segment. The results of operations of the Peaker assets are presented within continuing operations in the Consolidated Statements of Operations. The income / (loss) from continuing operations before income tax for the Peaker assets was $7.2 million (excluding loss on sale of $1.9 million ) and $0.3 million for the three months ended March 31, 2018 and 2017, respectively.
Subsidiaries [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Discontinued Operations	Generation Separation On October 1, 2017, DP&L completed the transfer of its generating plants, the real property on which the generation plants and generation-related assets are sited, step-up transformers and other transmission plant assets used to interconnect with the electric transmission grid, fuel inventory, equipment inventory and spare parts, working capital, and other miscellaneous generation-related assets and liabilities ("Generation assets") to AES Ohio Generation. The transfer was completed as a contribution through an asset contribution agreement to a wholly-owned subsidiary of DP&L after which DP&L then distributed all of the outstanding equity in the subsidiary to DPL and then the subsidiary was merged into AES Ohio Generation. 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 three months ended March 31, 2017 . The following table summarizes the revenues, cost of revenues, operating and other expenses and income tax of discontinued operations for the period indicated: Three months ended March 31, 2017 Revenues $ 121.0 Cost of revenues (69.8 ) Operating and other expenses (73.6 ) Fixed-asset impairment (66.3 ) Loss from discontinued operations (88.7 ) Income tax benefit from discontinued operations (29.9 ) Net loss from discontinued operations $ (58.8 ) Cash flows related to discontinued operations are included in the Statements of Cash Flows. Cash flows from operating activities for discontinued operations were $(11.8) million for the three months ended March 31, 2017 . Cash flows from investing activities for discontinued operations were $12.9 million for the three months ended March 31, 2017 . Cash flows from financing activities for discontinued operations were $(1.1) million for the three months ended March 31, 2017 . 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 was included in the discontinued operations above. The interest expense included in discontinued operations was $0.2 million for the three months ended March 31, 2017 . 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 three months ended March 31, 2018 and 2017.

Fixed-asset Impairment (Notes)

Fixed-asset Impairment (Notes)	3 Months Ended
	Mar. 31, 2018
Finite-Lived Intangible Assets [Line Items]
Asset Impairment Charges [Text Block]	Fixed-asset Impairments On March 17, 2017, the Board of Directors of DP&L approved the retirement of the two DP&L operated and co-owned electric generating stations; the Stuart station coal-fired and diesel-fired generating units and the Killen station coal-fired generating unit and combustion turbine (collectively, the “Facilities”) on or before June 1, 2018. The co-owners of these facilities agreed with DP&L to proceed with this plan of retirement. We performed a long-lived asset impairment analysis and determined that the carrying amounts of the Facilities were not recoverable. The asset groups of Stuart station and Killen station were determined to have fair values of $3.3 million and $7.9 million , respectively, using the discounted cash flows under the income approach. As a result, we recognized asset impairment expense of $39.1 million and $27.3 million for Stuart station and Killen station, respectively, during the first quarter of 2017. Additionally, as a result of the decision to retire the Facilities by June 1, 2018, we concluded that inventory at these Facilities is considered obsolete. As a result, we recognized a loss on disposal of $9.8 million and $6.4 million for Stuart station and Killen station inventories, respectively, during the first quarter of 2017, which is recorded in Other operating expenses in the Condensed Consolidated Statements of Operations.

Generation Separation (Notes)

Generation Separation (Notes)	3 Months Ended
	Mar. 31, 2018
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Discontinued Operations	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 three months ended March 31, 2018 and 2017. Prior to the transfer, the Beckjord Facility was included in the T&D segment. Peaker Assets – On March 27, 2018, DPL and AES Ohio Generation completed the sale transaction of the Peaker assets to Kimura Power, LLC for total proceeds of $239.3 million , which will be subject to a customary post-closing reconciliation. This transaction resulted in a loss on sale of $1.9 million for the three months ended March 31, 2018. Prior to the sale, the Peaker assets were included in the Generation segment. The results of operations of the Peaker assets are presented within continuing operations in the Consolidated Statements of Operations. The income / (loss) from continuing operations before income tax for the Peaker assets was $7.2 million (excluding loss on sale of $1.9 million ) and $0.3 million for the three months ended March 31, 2018 and 2017, respectively.
Subsidiaries [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Discontinued Operations	Generation Separation On October 1, 2017, DP&L completed the transfer of its generating plants, the real property on which the generation plants and generation-related assets are sited, step-up transformers and other transmission plant assets used to interconnect with the electric transmission grid, fuel inventory, equipment inventory and spare parts, working capital, and other miscellaneous generation-related assets and liabilities ("Generation assets") to AES Ohio Generation. The transfer was completed as a contribution through an asset contribution agreement to a wholly-owned subsidiary of DP&L after which DP&L then distributed all of the outstanding equity in the subsidiary to DPL and then the subsidiary was merged into AES Ohio Generation. 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 three months ended March 31, 2017 . The following table summarizes the revenues, cost of revenues, operating and other expenses and income tax of discontinued operations for the period indicated: Three months ended March 31, 2017 Revenues $ 121.0 Cost of revenues (69.8 ) Operating and other expenses (73.6 ) Fixed-asset impairment (66.3 ) Loss from discontinued operations (88.7 ) Income tax benefit from discontinued operations (29.9 ) Net loss from discontinued operations $ (58.8 ) Cash flows related to discontinued operations are included in the Statements of Cash Flows. Cash flows from operating activities for discontinued operations were $(11.8) million for the three months ended March 31, 2017 . Cash flows from investing activities for discontinued operations were $12.9 million for the three months ended March 31, 2017 . Cash flows from financing activities for discontinued operations were $(1.1) million for the three months ended March 31, 2017 . 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 was included in the discontinued operations above. The interest expense included in discontinued operations was $0.2 million for the three months ended March 31, 2017 . 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 three months ended March 31, 2018 and 2017.

Discontinued Operations

Discontinued Operations	3 Months Ended
	Mar. 31, 2018
Discontinued Operations and Disposal Groups [Abstract]
Discontinued Operations	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 three months ended March 31, 2018 and 2017. Prior to the transfer, the Beckjord Facility was included in the T&D segment. Peaker Assets – On March 27, 2018, DPL and AES Ohio Generation completed the sale transaction of the Peaker assets to Kimura Power, LLC for total proceeds of $239.3 million , which will be subject to a customary post-closing reconciliation. This transaction resulted in a loss on sale of $1.9 million for the three months ended March 31, 2018. Prior to the sale, the Peaker assets were included in the Generation segment. The results of operations of the Peaker assets are presented within continuing operations in the Consolidated Statements of Operations. The income / (loss) from continuing operations before income tax for the Peaker assets was $7.2 million (excluding loss on sale of $1.9 million ) and $0.3 million for the three months ended March 31, 2018 and 2017, respectively.

Held for Sale (Notes)

Held for Sale (Notes)	3 Months Ended
	Mar. 31, 2018
Long Lived Assets Held-for-sale [Line Items]
Discontinued Operations	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 three months ended March 31, 2018 and 2017. Prior to the transfer, the Beckjord Facility was included in the T&D segment. Peaker Assets – On March 27, 2018, DPL and AES Ohio Generation completed the sale transaction of the Peaker assets to Kimura Power, LLC for total proceeds of $239.3 million , which will be subject to a customary post-closing reconciliation. This transaction resulted in a loss on sale of $1.9 million for the three months ended March 31, 2018. Prior to the sale, the Peaker assets were included in the Generation segment. The results of operations of the Peaker assets are presented within continuing operations in the Consolidated Statements of Operations. The income / (loss) from continuing operations before income tax for the Peaker assets was $7.2 million (excluding loss on sale of $1.9 million ) and $0.3 million for the three months ended March 31, 2018 and 2017, respectively.
Subsidiaries [Member]
Long Lived Assets Held-for-sale [Line Items]
Discontinued Operations	Generation Separation On October 1, 2017, DP&L completed the transfer of its generating plants, the real property on which the generation plants and generation-related assets are sited, step-up transformers and other transmission plant assets used to interconnect with the electric transmission grid, fuel inventory, equipment inventory and spare parts, working capital, and other miscellaneous generation-related assets and liabilities ("Generation assets") to AES Ohio Generation. The transfer was completed as a contribution through an asset contribution agreement to a wholly-owned subsidiary of DP&L after which DP&L then distributed all of the outstanding equity in the subsidiary to DPL and then the subsidiary was merged into AES Ohio Generation. 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 three months ended March 31, 2017 . The following table summarizes the revenues, cost of revenues, operating and other expenses and income tax of discontinued operations for the period indicated: Three months ended March 31, 2017 Revenues $ 121.0 Cost of revenues (69.8 ) Operating and other expenses (73.6 ) Fixed-asset impairment (66.3 ) Loss from discontinued operations (88.7 ) Income tax benefit from discontinued operations (29.9 ) Net loss from discontinued operations $ (58.8 ) Cash flows related to discontinued operations are included in the Statements of Cash Flows. Cash flows from operating activities for discontinued operations were $(11.8) million for the three months ended March 31, 2017 . Cash flows from investing activities for discontinued operations were $12.9 million for the three months ended March 31, 2017 . Cash flows from financing activities for discontinued operations were $(1.1) million for the three months ended March 31, 2017 . 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 was included in the discontinued operations above. The interest expense included in discontinued operations was $0.2 million for the three months ended March 31, 2017 . 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 three months ended March 31, 2018 and 2017.

Summary of Significant Accounti

Summary of Significant Accounting Policies (Policy)	3 Months Ended
	Mar. 31, 2018
Significant Accounting Policies [Line Items]
Description of Business	Description of Business DPL is a diversified regional energy company organized in 1985 under the laws of Ohio. DPL has two reportable segments: the T&D segment and the Generation segment. See Note 12 – Business Segments for more information relating to these reportable segments. The terms “we,” “us,” “our” and “ours” are used to refer to DPL and its subsidiaries. DPL is an indirectly wholly-owned subsidiary of AES. DP&L , a wholly-owned subsidiary of DPL , is a public utility incorporated in 1911 under the laws of Ohio. Beginning in 2001, Ohio law gave Ohio consumers the right to choose the electric generation supplier from whom they purchase retail generation service; however, retail transmission and distribution services are still regulated. DP&L has the exclusive right to provide such transmission and distribution services to approximately 523,000 customers located in West Central Ohio. Additionally, 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. Through September 30, 2017, DP&L owned undivided interests in multiple coal-fired and peaking electric generating facilities as well as numerous transmission facilities. On October 1, 2017, the DP&L -owned generating facilities were transferred to AES Ohio Generation, an affiliate of DP&L and wholly-owned subsidiary of DPL , through an asset contribution agreement to a subsidiary that was merged into AES Ohio Generation. Principal industries located in DP&L’s service territory include automotive, food processing, paper, plastic, health care, data management, manufacturing and defense. DP&L's distribution sales reflect the general economic conditions, seasonal weather patterns, the proliferation of energy efficiency and distributed renewable resources and the market price of electricity. Through September 30, 2017, DP&L sold its generated energy and capacity into the wholesale market. After September 30, 2017, DP&L continues to sell its proportional share of energy and capacity from its investment in OVEC. DPL’s other significant subsidiaries include MVIC and AES Ohio Generation. MVIC is our captive insurance company that provides insurance services to DPL and our other subsidiaries. AES Ohio Generation owns and operates certain coal-fired generating facilities . AES Ohio Generation sells all of its energy and capacity into the wholesale market. DPL's subsidiaries are all wholly-owned. DPL also has a wholly-owned business trust, DPL Capital Trust II, formed for the purpose of issuing trust capital securities to investors. DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates, and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs. DPL and its subsidiaries employed 1,051 people as of March 31, 2018 , of which 673 were employed by DP&L . Approximately 59% of all DP&L and AES Ohio Generation employees are under a collective bargaining agreement. The current agreement, after initially being extended, expired on January 31, 2018. Under national labor law, all the terms and conditions of the expired agreement continue indefinitely, subject to certain exceptions. Notably, the union has the right to strike and DP&L and AES Ohio Generation have the right to lock out employees. We are continuing to negotiate with the union to enter into a new collective bargaining agreement. Currently, we are unable to predict the eventual outcome of these negotiations and have contingency plans to continue our operations if the negotiations are not successful. If we are not able to reach an agreement on terms favorable to us or to effectively implement our plans in the event that agreement is not reached, our results of operations, financial position and cash flows could be adversely impacted.
Financial Statement Presentation	Financial Statement Presentation DPL’s Condensed 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. As of March 31, 2018 , DPL has undivided ownership interests in three coal-fired generating facilities and numerous transmission facilities, all of which are included in the financial statements at the lower of depreciated historical cost or fair value, if impaired. Operating revenues and expenses of these facilities are included on a pro rata basis in the corresponding lines in the Condensed Consolidated Statements of Operations. Certain immaterial amounts from prior periods have been reclassified to conform to the current period presentation. All material intercompany accounts and transactions are eliminated in consolidation. These financial statements have been prepared in accordance with GAAP for interim financial statements, the instructions of Form 10-Q and Regulation S-X. Accordingly, certain information and footnote disclosures normally included in the annual financial statements prepared in accordance with GAAP have been omitted from this interim report. Therefore, our interim financial statements in this report should be read along with the annual financial statements included in our Form 10-K for the fiscal year ended December 31, 2017 . In the opinion of our management, the Condensed Consolidated Financial Statements presented in this report contain all adjustments necessary to fairly state our financial position as of March 31, 2018 ; our results of operations for the three months ended March 31, 2018 and 2017 and our cash flows for the three months ended March 31, 2018 and 2017 . Unless otherwise noted, all adjustments are normal and recurring in nature. Due to various factors, including, but not limited to, seasonal weather variations, the timing of outages of EGUs, changes in economic conditions involving commodity prices and competition, and other factors, interim results for the three months ended March 31, 2018 may not be indicative of our results that will be realized for the full year ending December 31, 2018 . 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: recognition of revenue including unbilled revenues, the carrying value of property, plant and equipment; 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; liabilities recorded for income tax exposures; litigation; contingencies; the valuation of AROs; and assets and liabilities related to employee benefits.
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. These taxes are accounted for on a net basis and not included in revenue. The amounts of such taxes collected for the three months ended March 31, 2018 and 2017 were $13.1 million and $12.5 million, respectively.
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. ASU Number and Name Description Date of Adoption Effect on the financial statements upon adoption New Accounting Standards Adopted 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities This standard requires equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) be measured at fair value with changes in fair value recognized in net income. However, an entity may choose to measure equity investments that do not have readily determinable fair values at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or a similar investment of the same issuer. 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 Retained Earnings. 2017-07, Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost This standard changes the presentation of non-service cost expense associated with defined benefit plans and updates the guidance so that only the service cost component will be eligible for capitalization. January 1, 2018 The adoption of this standard resulted in a $3.6 million reclassification of non-service pension and other postretirement benefit costs from Operating expense to Other income / (deductions) - net for the three months ended March 31, 2017. 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 The adoption of this standard resulted in a $20.6 million decrease in investing activities for the three months ended March 31, 2017. 2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-05, 2017-13 Revenue from Contracts with Customers (Topic 606) See " Adoption of FASC Topic 606, Revenue from Contracts with Customers " 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 ("ASC 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 ASC 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, ASC 605. 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 Condensed Consolidated Balance Sheet resulting from the adoption of FASC 606. See additional disclosures under ASC 606 in Note 13 – Revenue . 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. ASU Number and Name 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. We are currently evaluating the impact of adopting the standard on our consolidated financial statements. 2017-12, Derivatives and Hedging (Topic 815): Targeted improvements to Accounting for Hedging Activities The standard updates the hedge accounting model to expand the ability to hedge nonfinancial and financial risk components, reduce complexity, and ease certain documentation and assessment requirements. When facts and circumstances are the same as at the previous quantitative test, a subsequent quantitative effectiveness test is not required. The standard also eliminates the requirement to separately measure and report hedge ineffectiveness. For cash flow hedges, this means that the entire change in the fair value of a hedging instrument will be recorded in other comprehensive income and amounts deferred will be reclassified to earnings in the same income statement line as the hedged item. January 1, 2019. We are currently evaluating the impact of adopting the standard on our consolidated financial statements. 2017-08, Receivables - Nonrefundable Fees and Other Costs (Subtopic 310-20): Premium Amortization on Purchased Callable Debt Securities This standard shortens the period of amortization of the premium on certain callable debt securities to the earliest call date. January 1, 2019. We are currently evaluating the impact of adopting the standard on our consolidated financial statements. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments This standard updates the impairment model for financial assets measured at amortized cost to an expected loss model rather than an incurred loss model. It also allows for the presentation of credit losses on available-for-sale debt securities as an allowance rather than a write down. January 1, 2020. We are currently evaluating the impact of adopting the standard on our consolidated financial statements. 2016-02, 2018-01, Leases (Topic 842) See " 2016-02, Leases (Topic 842) " below. January 1, 2019. We are currently evaluating the impact of adopting the standard on our consolidated financial statements. 2016-02, 2018-01, Leases (Topic 842) 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 current accounting methods. For Lessors, the guidance modifies the lease classification criteria and the accounting for sales-type and direct financing leases. The guidance also eliminates current real estate-specific provisions. The standard must be adopted using a modified retrospective adoption at the beginning of the earliest comparative period presented in the financial statements (January 1, 2017). The FASB proposed amending the standard to give another option for transition. The proposed transition method would allow entities to not apply the new lease standard in the comparative periods presented in their financial statements in the year of adoption. Under the proposed transition method, the entity would apply the transition provisions on January 1, 2019 (i.e., the effective date). At transition, lessees and lessors are permitted to make an election to apply a package of practical expedients that allow them not to reassess: (1) whether any expired or existing contracts are or contain leases, (2) lease classification for any expired or existing leases, and (3) whether initial direct costs for any expired or existing leases qualify for capitalization under FASC 842. These three practical expedients must be elected as a package and must be consistently applied to all leases. Furthermore, entities are also permitted to make an election to use hindsight when determining lease term and entities can elect to use hindsight when assessing the impairment of right-of-use assets. We have established a task force focused on the identification of contracts that would be under the scope of the new standard and on the assessment and measurement of the right-of-use asset and related liability. Additionally, the implementation team has been working on the identification and selection of a lease accounting system that would support the implementation and the subsequent accounting. The implementation team is in the process of evaluating changes to our business processes, systems and controls to support recognition and disclosure under the new standard. As we have preliminarily concluded that at transition we would be using the package of practical expedients, the main impact expected as of the effective date is the recognition of the right to use asset and the related liability in the financial statements for all those contracts that contain a lease and for which we are the lessee. However, income statement presentation and the expense recognition pattern are not expected to change. Under FASC 842, it is expected that fewer contracts will contain a lease. However, due to the elimination of today's real estate-specific guidance and changes to certain lessor classification criteria, more leases will qualify as sales-type leases and direct financing leases. Under these two models, a lessor will derecognize the asset and will recognize a lease receivable. According to FASC 842, the lease receivable does not include variable payments that depend on the use of the asset (e.g. MWh produced by a facility). Therefore, the lease receivable could be lower than the carrying amount of the underlying asset at lease commencement. In such circumstances, the difference between the initially recognized lease receivable and the carrying amount of the underlying asset is recognized as a selling loss at lease commencement.
THE DAYTON POWER AND LIGHT COMPANY [Member]
Significant Accounting Policies [Line Items]
Description of Business	Description of Business DP&L is a public utility incorporated in 1911 under the laws of Ohio. Beginning in 2001, Ohio law gave Ohio consumers the right to choose the electric generation supplier from whom they purchase retail generation service; however, retail transmission and distribution services are still regulated. DP&L has the exclusive right to provide such transmission and distribution services to approximately 523,000 customers located in West Central Ohio. Additionally, 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. Through September 30, 2017, DP&L owned undivided interests in multiple coal-fired and peaking electric generating facilities as well as numerous transmission facilities. On October 1, 2017, the DP&L -owned generating facilities were transferred to AES Ohio Generation, an affiliate of DP&L and wholly-owned subsidiary of DPL , through an asset contribution agreement to a subsidiary that was merged into AES Ohio Generation. 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 have either been closed or sold. Principal industries located in DP&L’s service territory include automotive, food processing, paper, plastic, health care, data management, manufacturing and defense. DP&L's distribution sales reflect the general economic conditions, seasonal weather patterns, the proliferation of energy efficiency and distributed renewable resources and the market price of electricity. Through September 30, 2017, DP&L sold its generated energy and capacity into the wholesale market. After September 30, 2017, DP&L continues to sell its proportional share of energy and capacity from its investment in OVEC. DP&L is a subsidiary of DPL . The terms “we,” “us,” “our” and “ours” are used to refer to DP&L . DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates, and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs. DP&L employed 673 people as of March 31, 2018 . Approximately 53% of DP&L employees are under a collective bargaining agreement. The current agreement, after initially being extended, expired on January 31, 2018. Under national labor law, all the terms and conditions of the expired agreement continue indefinitely, subject to certain exceptions. Notably, the union has the right to strike and DP&L has the right to lock out employees. We are continuing to negotiate with the union to enter into a new collective bargaining agreement. Currently, we are unable to predict the eventual outcome of these negotiations and have contingency plans to continue our operations if the negotiations are not successful. If we are not able to reach an agreement on terms favorable to us or to effectively implement our plans in the event that agreement is not reached, our results of operations, financial position and cash flows could be adversely impacted.
Financial Statement Presentation	Financial Statement Presentation DP&L does not have any subsidiaries. Certain immaterial amounts from prior periods have been reclassified to conform to the current period presentation. These financial statements have been prepared in accordance with GAAP for interim financial statements, the instructions of Form 10-Q and Regulation S-X. Accordingly, certain information and footnote disclosures normally included in the annual financial statements prepared in accordance with GAAP have been omitted from this interim report. Therefore, our interim financial statements in this report should be read along with the annual financial statements included in our Form 10-K for the fiscal year ended December 31, 2017 . In the opinion of our management, the Condensed Financial Statements presented in this report contain all adjustments necessary to fairly state our financial position as of March 31, 2018 ; our results of operations for the three months ended March 31, 2018 and 2017 and our cash flows for the three months ended March 31, 2018 and 2017 . Unless otherwise noted, all adjustments are normal and recurring in nature. Due to various factors, including, but not limited to, seasonal weather variations, the timing of outages of EGUs, changes in economic conditions involving commodity prices and competition, and other factors, interim results for the three months ended March 31, 2018 may not be indicative of our results that will be realized for the full year ending December 31, 2018 . 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: recognition of revenue including unbilled revenues, the carrying value of property, plant and equipment; 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; liabilities recorded for income tax exposures; litigation; contingencies; the valuation of AROs; and assets and liabilities related to employee benefits.
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. These taxes are accounted for on a net basis and not included in revenue. The amounts of such taxes collected for the three months ended March 31, 2018 and 2017 were $13.1 million and $12.5 million, respectively.
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 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. ASU Number and Name Description Date of Adoption Effect on the financial statements upon adoption New Accounting Standards Adopted 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities This standard requires equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) be measured at fair value with changes in fair value recognized in net income. However, an entity may choose to measure equity investments that do not have readily determinable fair values at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or a similar investment of the same issuer. 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. 2017-07, Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost This standard changes the presentation of non-service cost expense associated with defined benefit plans and updates the guidance so that only the service cost component will be eligible for capitalization. January 1, 2018 The adoption of this standard resulted in a $0.8 million reclassification of non-service pension and other postretirement benefit costs from Operating expense to Other income / (deductions) - net for the three months ended March 31, 2017. ASU Number and Name Description Date of Adoption Effect on the financial statements upon adoption 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 The adoption of this standard resulted in a $20.6 million decrease in investing activities for the three months ended March 31, 2017. 2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-05, 2017-13 Revenue from Contracts with Customers (Topic 606) See " Adoption of FASC Topic 606, Revenue from Contracts with Customers " 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 ("ASC 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 ASC 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, ASC 605. 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 Condensed Consolidated Balance Sheet resulting from the adoption of FASC 606. See additional disclosures under ASC 606 in Note 12 – Revenue . 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 financial statements. ASU Number and Name 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. We are currently evaluating the impact of adopting the standard on our financial statements. ASU Number and Name Description Date of Adoption Effect on the financial statements upon adoption 2017-12, Derivatives and Hedging (Topic 815): Targeted improvements to Accounting for Hedging Activities The standard updates the hedge accounting model to expand the ability to hedge nonfinancial and financial risk components, reduce complexity, and ease certain documentation and assessment requirements. When facts and circumstances are the same as at the previous quantitative test, a subsequent quantitative effectiveness test is not required. The standard also eliminates the requirement to separately measure and report hedge ineffectiveness. For cash flow hedges, this means that the entire change in the fair value of a hedging instrument will be recorded in other comprehensive income and amounts deferred will be reclassified to earnings in the same income statement line as the hedged item. January 1, 2019. We are currently evaluating the impact of adopting the standard on our financial statements. 2017-08, Receivables - Nonrefundable Fees and Other Costs (Subtopic 310-20): Premium Amortization on Purchased Callable Debt Securities This standard shortens the period of amortization of the premium on certain callable debt securities to the earliest call date. January 1, 2019. We are currently evaluating the impact of adopting the standard on our financial statements. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments This standard updates the impairment model for financial assets measured at amortized cost to an expected loss model rather than an incurred loss model. It also allows for the presentation of credit losses on available-for-sale debt securities as an allowance rather than a write down. January 1, 2020. We are currently evaluating the impact of adopting the standard on our financial statements. 2016-02, 2018-01, Leases (Topic 842) See " 2016-02, Leases (Topic 842) " below. January 1, 2019. We are currently evaluating the impact of adopting the standard on our financial statements. 2016-02, 2018-01, Leases (Topic 842) 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 current accounting methods. For Lessors, the guidance modifies the lease classification criteria and the accounting for sales-type and direct financing leases. The guidance also eliminates current real estate-specific provisions. The standard must be adopted using a modified retrospective adoption at the beginning of the earliest comparative period presented in the financial statements (January 1, 2017). The FASB proposed amending the standard to give another option for transition. The proposed transition method would allow entities to not apply the new lease standard in the comparative periods presented in their financial statements in the year of adoption. Under the proposed transition method, the entity would apply the transition provisions on January 1, 2019 (i.e., the effective date). At transition, lessees and lessors are permitted to make an election to apply a package of practical expedients that allow them not to reassess: (1) whether any expired or existing contracts are or contain leases, (2) lease classification for any expired or existing leases, and (3) whether initial direct costs for any expired or existing leases qualify for capitalization under FASC 842. These three practical expedients must be elected as a package and must be consistently applied to all leases. Furthermore, entities are also permitted to make an election to use hindsight when determining lease term and entities can elect to use hindsight when assessing the impairment of right-of-use assets. We have established a task force focused on the identification of contracts that would be under the scope of the new standard and on the assessment and measurement of the right-of-use asset and related liability. Additionally, the implementation team has been working on the identification and selection of a lease accounting system that would support the implementation and the subsequent accounting. The implementation team is in the process of evaluating changes to our business processes, systems and controls to support recognition and disclosure under the new standard. As we have preliminarily concluded that at transition we would be using the package of practical expedients, the main impact expected as of the effective date is the recognition of the right to use asset and the related liability in the financial statements for all those contracts that contain a lease and for which we are the lessee. However, income statement presentation and the expense recognition pattern are not expected to change. Under FASC 842, it is expected that fewer contracts will contain a lease. However, due to the elimination of today's real estate-specific guidance and changes to certain lessor classification criteria, more leases will qualify as sales-type leases and direct financing leases. Under these two models, a lessor will derecognize the asset and will recognize a lease receivable. According to FASC 842, the lease receivable does not include variable payments that depend on the use of the asset (e.g. MWh produced by a facility). Therefore, the lease receivable could be lower than the carrying amount of the underlying asset at lease commencement. In such circumstances, the difference between the initially recognized lease receivable and the carrying amount of the underlying asset is recognized as a selling loss at lease commencement.

Generation Separation (Policies

Generation Separation (Policies)	3 Months Ended
	Mar. 31, 2018
Subsidiaries [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Discontinued Operations, Policy [Policy Text Block]	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 was included in the discontinued operations above. The interest expense included in discontinued operations was $0.2 million for the three months ended March 31, 2017 .

Summary of Significant Accoun28

Summary of Significant Accounting Policies (Tables)	3 Months Ended
	Mar. 31, 2018
Related Party Transaction [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 Condensed Consolidated Balance Sheet that reconcile to the total of such amounts as shown on the Condensed Consolidated Statements of Cash Flows: $ in millions March 31, 2018 December 31, 2017 Cash and cash equivalents $ 123.9 $ 24.5 Restricted cash 27.4 1.9 Cash, Cash Equivalents, and Restricted Cash, End of Period $ 151.3 $ 26.4
Schedule of New Accounting Pronouncements	– 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. ASU Number and Name Description Date of Adoption Effect on the financial statements upon adoption New Accounting Standards Adopted 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities This standard requires equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) be measured at fair value with changes in fair value recognized in net income. However, an entity may choose to measure equity investments that do not have readily determinable fair values at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or a similar investment of the same issuer. 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 Retained Earnings. 2017-07, Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost This standard changes the presentation of non-service cost expense associated with defined benefit plans and updates the guidance so that only the service cost component will be eligible for capitalization. January 1, 2018 The adoption of this standard resulted in a $3.6 million reclassification of non-service pension and other postretirement benefit costs from Operating expense to Other income / (deductions) - net for the three months ended March 31, 2017. 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 The adoption of this standard resulted in a $20.6 million decrease in investing activities for the three months ended March 31, 2017. 2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-05, 2017-13 Revenue from Contracts with Customers (Topic 606) See " Adoption of FASC Topic 606, Revenue from Contracts with Customers " 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 ("ASC 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 ASC 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, ASC 605. 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 Condensed Consolidated Balance Sheet resulting from the adoption of FASC 606. See additional disclosures under ASC 606 in Note 13 – Revenue . 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. ASU Number and Name 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. We are currently evaluating the impact of adopting the standard on our consolidated financial statements. 2017-12, Derivatives and Hedging (Topic 815): Targeted improvements to Accounting for Hedging Activities The standard updates the hedge accounting model to expand the ability to hedge nonfinancial and financial risk components, reduce complexity, and ease certain documentation and assessment requirements. When facts and circumstances are the same as at the previous quantitative test, a subsequent quantitative effectiveness test is not required. The standard also eliminates the requirement to separately measure and report hedge ineffectiveness. For cash flow hedges, this means that the entire change in the fair value of a hedging instrument will be recorded in other comprehensive income and amounts deferred will be reclassified to earnings in the same income statement line as the hedged item. January 1, 2019. We are currently evaluating the impact of adopting the standard on our consolidated financial statements. 2017-08, Receivables - Nonrefundable Fees and Other Costs (Subtopic 310-20): Premium Amortization on Purchased Callable Debt Securities This standard shortens the period of amortization of the premium on certain callable debt securities to the earliest call date. January 1, 2019. We are currently evaluating the impact of adopting the standard on our consolidated financial statements. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments This standard updates the impairment model for financial assets measured at amortized cost to an expected loss model rather than an incurred loss model. It also allows for the presentation of credit losses on available-for-sale debt securities as an allowance rather than a write down. January 1, 2020. We are currently evaluating the impact of adopting the standard on our consolidated financial statements. 2016-02, 2018-01, Leases (Topic 842) See " 2016-02, Leases (Topic 842) " below. January 1, 2019. We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
THE DAYTON POWER AND LIGHT COMPANY [Member]
Related Party Transaction [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 Condensed Balance Sheet that reconcile to the total of such amounts as shown on the Condensed Statements of Cash Flows: $ in millions March 31, 2018 December 31, 2017 Cash and cash equivalents $ 1.0 $ 5.2 Restricted cash 0.9 0.4 Cash, Cash Equivalents, and Restricted Cash, End of Period $ 1.9 $ 5.6

Supplemental Financial Inform29

Supplemental Financial Information (Tables)	3 Months Ended
	Mar. 31, 2018
Supplemental Financial Information [Line Items]
Schedule of Supplemental Financial Information	March 31, 2018 and December 31, 2017 : March 31, December 31, $ in millions 2018 2017 Accounts receivable, net: Unbilled revenue $ 12.1 $ 18.0 Customer receivables 65.7 57.8 Amounts due from partners in jointly-owned plants 13.6 19.1 Other 10.9 4.9 Provision for uncollectible accounts (1.1 ) (1.1 ) Total accounts receivable, net $ 101.2 $ 98.7 Inventories, at average cost: Fuel and limestone $ 13.3 $ 15.5 Plant materials and supplies 8.4 8.5 Other 0.6 0.5 Total inventories, at average cost $ 22.3 $ 24.5
Reclassification out of Accumulated Other Comprehensive Income	The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the three months ended March 31, 2018 and 2017 are as follows: Details about Accumulated Other Comprehensive Income / (Loss) components Affected line item in the Condensed Consolidated Statements of Operations Three months ended March 31, $ in millions 2018 2017 Gains and losses on equity securities (Note 5): Other income $ — $ (0.1 ) Retained earnings (1.6 ) — Tax expense 0.6 — Net of income taxes (1.0 ) (0.1 ) Gains and losses on cash flow hedges (Note 6): Interest expense (1.1 ) (0.3 ) Revenue (2.0 ) (1.5 ) Purchased power 6.2 3.3 Total before income taxes 3.1 1.5 Tax benefit (0.8 ) (0.5 ) Net of income taxes 2.3 1.0 Amortization of defined benefit pension items (Note 9): Operation and maintenance 0.2 1.3 Tax benefit (0.1 ) (0.5 ) Net of income taxes 0.1 0.8 Total reclassifications for the period, net of income taxes $ 1.4 $ 1.7
Schedule of Accumulated Other Comprehensive Income (Loss)	Accumulated Other Comprehensive Income / (Loss) during the three months ended March 31, 2018 are as follows: $ in millions Gains / (losses) on equity securities Gains / (losses) on cash flow hedges Change in unfunded pension obligation Total Balance at January 1, 2018 $ 1.0 $ 14.7 $ (14.9 ) $ 0.8 Other comprehensive income before reclassifications — 0.9 — 0.9 Amounts reclassified from accumulated other comprehensive income / (loss) to earnings — 2.3 0.1 2.4 Amounts reclassified from accumulated other comprehensive income / (loss) to Retained earnings (1.0 ) — — (1.0 ) Net current period other comprehensive income / (loss) (1.0 ) 3.2 0.1 2.3 Balance at March 31, 2018 $ — $ 17.9 $ (14.8 ) $ 3.1
Schedule of Other Operating Cost and Expense, by Component [Table Text Block]	Operating expenses - other Operating expenses - other generally includes gains or losses on asset sales or dispositions, insurance recoveries, gains or losses on the sale of businesses and other expense or income from miscellaneous transactions. The components are summarized as follows: Three months ended March 31, $ in millions 2018 2017 Loss on asset disposal, net $ 0.6 $ 19.4 Loss on disposal and sale of businesses 13.6 — Insurance recoveries — (1.2 ) Other 0.7 — Net other expense / (income) $ 14.9 $ 18.2
THE DAYTON POWER AND LIGHT COMPANY [Member]
Supplemental Financial Information [Line Items]
Schedule of Supplemental Financial Information	March 31, 2018 and December 31, 2017 : March 31, December 31, $ in millions 2018 2017 Accounts receivable, net: Unbilled revenue $ 12.1 $ 18.0 Customer receivables 49.8 44.2 Amounts due from affiliates 3.8 — Amounts due from partners in jointly-owned plants 2.1 5.0 Other 6.3 4.7 Provision for uncollectible accounts (1.1 ) (1.1 ) Total accounts receivable, net $ 73.0 $ 70.8 Inventories, at average cost: Plant materials and supplies $ 7.0 $ 6.9 Other 0.6 0.4 Total inventories, at average cost $ 7.6 $ 7.3
Reclassification out of Accumulated Other Comprehensive Income	The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the three months ended March 31, 2018 and 2017 are as follows: Details about Accumulated Other Comprehensive Income / (Loss) components Affected line item in the Condensed Statements of Operations Three months ended March 31, $ in millions 2018 2017 Gains and losses on equity securities activity (Note 5): Other income $ — $ (0.1 ) Retained earnings (1.7 ) — Tax benefit 0.6 — Net of income taxes (1.1 ) (0.1 ) Gains and losses on cash flow hedges (Note 6): Interest expense (0.8 ) (0.3 ) Tax benefit from continuing operations 0.5 0.1 Gain from discontinued operations — 1.8 Tax expense from discontinued operations — (0.6 ) Net of income taxes (0.3 ) 1.0 Amortization of defined benefit pension items (Note 9): Operation and maintenance 1.1 3.8 Tax expense (0.2 ) (1.3 ) Net of income taxes 0.9 2.5 Total reclassifications for the period, net of income taxes $ (0.5 ) $ 3.4
Schedule of Accumulated Other Comprehensive Income (Loss)	The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the three months ended March 31, 2018 are as follows: $ in millions Gains / (losses) on equity securities Gains / (losses) on cash flow hedges Change in unfunded pension obligation Total Balance at January 1, 2018 $ 1.1 $ 1.4 $ (38.7 ) $ (36.2 ) Other comprehensive income before reclassifications — 0.5 — 0.5 Amounts reclassified from accumulated other comprehensive income / (loss) to earnings — (0.3 ) 0.9 0.6 Amounts reclassified from accumulated other comprehensive income / (loss) to Retained earnings (1.1 ) — — (1.1 ) Net current period other comprehensive income / (loss) (1.1 ) 0.2 0.9 — Balance at March 31, 2018 $ — $ 1.6 $ (37.8 ) $ (36.2 )

Property, Plant and Equipment30

Property, Plant and Equipment (Tables)	3 Months Ended
	Mar. 31, 2018
Property, Plant and Equipment [Line Items]
Schedule of Jointly Owned Utility Plants [Table Text Block]	DPL's undivided ownership interest in such facilities at March 31, 2018 , was as follows: DPL Share DPL Carrying Value Ownership Summer Production Capacity Gross Plant Accumulated Construction Jointly-owned production units Conesville - Unit 4 16.5 129 $ 0.6 $ 0.6 $ 2.3 Killen - Unit 2 67.0 402 9.5 9.1 — Stuart - Units 2 through 4 35.0 606 1.8 1.8 — Transmission (at varying percentages) 39.4 9.0 — Total 1,137 $ 51.3 $ 20.5 $ 2.3 Each of the above generating units has SCR and FGD equipment installed.
Schedule of Change in Asset Retirement Obligation [Table Text Block]	Changes in the Liability for AROs $ in millions Balance at January 1, 2018 $ 131.2 Accretion expense 0.7 Settlements (0.2 ) Reductions due to plant sales (3.4 ) Balance at March 31, 2018 $ 128.3 See Note 5 – Fair Value for further discussion on changes to our AROs.
Subsidiaries [Member]
Property, Plant and Equipment [Line Items]
Schedule of Change in Asset Retirement Obligation [Table Text Block]	Changes in the Liability for AROs $ in millions Balance at January 1, 2018 $ 8.0 Revisions to cash flow and timing estimates 0.1 Reductions due to plant sales (3.4 ) Balance at March 31, 2018 $ 4.7

Fair Value (Tables)

Fair Value (Tables)	3 Months Ended
	Mar. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value and Cost Of Non-Derivative Instruments	The following table presents the fair value, carrying value and cost of our non-derivative instruments at March 31, 2018 and December 31, 2017 . Information about the fair value of our derivative instruments can be found in Note 6 – Derivative Instruments and Hedging Activities . March 31, 2018 December 31, 2017 $ in millions Cost Fair Value Cost Fair Value Assets Money market funds $ 0.3 $ 0.3 $ 0.3 $ 0.3 Equity securities 2.4 3.8 2.5 4.2 Debt securities 4.3 4.2 4.3 4.3 Hedge funds 0.1 0.2 0.1 0.2 Tangible assets 0.1 0.1 0.1 0.1 Total Assets $ 7.2 $ 8.6 $ 7.3 $ 9.1 Carrying Value Fair Value Carrying Value Fair Value Liabilities Long-term debt (a) $ 1,576.6 $ 1,661.4 $ 1,704.8 $ 1,819.3 (a) Amounts exclude immaterial capital lease obligations at December 31, 2017
Fair Value of Assets and Liabilities Measured on Recurring Basis	The fair value of assets and liabilities at March 31, 2018 and December 31, 2017 and the respective category within the fair value hierarchy for DPL is as follows: Assets and Liabilities at Fair Value Level 1 Level 2 Level 3 $ in millions Fair value at March 31, 2018 (a) Based on Quoted Prices in Active Markets Other Observable Inputs Unobservable Inputs Assets Master Trust assets Money market funds $ 0.3 $ 0.3 $ — $ — Equity securities 3.8 — 3.8 — Debt securities 4.2 — 4.2 — Hedge funds 0.2 — 0.2 — Tangible assets 0.1 — 0.1 — Total Master Trust assets 8.6 0.3 8.3 — Derivative assets Interest rate hedges 1.9 — 1.9 — Total Derivative assets 1.9 — 1.9 — Total Assets $ 10.5 $ 0.3 $ 10.2 $ — Liabilities Derivative Liabilities FTRs $ 0.1 $ — $ — $ 0.1 Forward power contracts 0.1 — 0.1 — Total Derivative liabilities 0.2 — 0.1 0.1 Long-term debt 1,661.4 — 1,643.6 17.8 Total Liabilities $ 1,661.6 $ — $ 1,643.7 $ 17.9 (a) Includes credit valuation adjustment Assets and Liabilities at Fair Value Level 1 Level 2 Level 3 $ in millions Fair value at December 31, 2017 (a) Based on Quoted Prices in Active Markets Other Observable Inputs Unobservable Inputs Assets Master Trust assets Money market funds $ 0.3 $ 0.3 $ — $ — Equity securities 4.2 — 4.2 — Debt securities 4.3 — 4.3 — Hedge funds 0.2 — 0.2 — Tangible assets 0.1 — 0.1 — Total Master Trust assets 9.1 0.3 8.8 — Derivative assets Forward power contracts 10.8 — 10.8 — Interest rate hedges 1.8 — 1.8 — Natural gas 0.2 0.2 — — Total Derivative assets 12.8 0.2 12.6 — Total Assets $ 21.9 $ 0.5 $ 21.4 $ — Liabilities Derivative liabilities FTRs $ 0.3 $ — $ — $ 0.3 Natural gas 0.1 0.1 — — Forward power contracts 14.9 — 14.9 — Total Derivative liabilities 15.3 0.1 14.9 0.3 Long-term debt (b) 1,819.3 — 1,801.5 17.8 Total Liabilities $ 1,834.6 $ 0.1 $ 1,816.4 $ 18.1 (a) Includes credit valuation adjustment (b) Amounts exclude immaterial capital lease obligations
Fair Value Measurements, Nonrecurring [Table Text Block]	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 Long-lived assets measured at fair value on a non-recurring basis during the periods and their level within the fair value hierarchy: Carrying Fair Value Gross Amount (a) Level 1 Level 2 Level 3 Loss $ in millions Three months ended March 31, 2017 Assets Long-lived assets (b) Stuart $ 42.4 $ — $ — $ 3.3 $ 39.1 Killen $ 35.2 $ — $ — $ 7.9 $ 27.3 Total $ 66.4 (a) Carrying amount at date of valuation (b) See Note 15 – Fixed-asset Impairments for further information T
Fair Value Inputs, Assets, Quantitative Information [Table Text Block]	e following summarizes the significant unobservable inputs used in the Level 3 measurement on a non-recurring basis during the three months ended March 31, 2017: $ in millions Fair value Valuation technique Unobservable input Weighted average Long-lived assets held and used: Stuart $ 3.3 Discounted cash flow Pre-tax operating margin 10.0 % Weighted-average cost of capital 7.0 % Killen $ 7.9 Discounted cash flow Pre-tax operating margin 22.0 % Weighted-average cost of capital 7.0 %
THE DAYTON POWER AND LIGHT COMPANY [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value and Cost Of Non-Derivative Instruments	The following table presents the fair value, carrying value and cost of our non-derivative instruments at March 31, 2018 and December 31, 2017 . Information about the fair value of our derivative instruments can be found in Note 6 – Derivative Instruments and Hedging Activities . March 31, 2018 December 31, 2017 $ in millions Cost Fair Value Cost Fair Value Assets Money market funds $ 0.3 $ 0.3 $ 0.3 $ 0.3 Equity securities 2.4 3.8 2.5 4.2 Debt securities 4.3 4.2 4.3 4.3 Hedge funds 0.1 0.2 0.1 0.2 Real estate — — — — Tangible assets 0.1 0.1 0.1 0.1 Total assets $ 7.2 $ 8.6 $ 7.3 $ 9.1 Carrying Value Fair Value Carrying Value Fair Value Liabilities Long-term debt $ 587.7 $ 597.2 $ 646.6 $ 658.4
Fair Value of Assets and Liabilities Measured on Recurring Basis	The fair value of assets and liabilities at March 31, 2018 and December 31, 2017 and the respective category within the fair value hierarchy for DP&L is as follows: Assets and Liabilities at Fair Value Level 1 Level 2 Level 3 $ in millions Fair value at March 31, 2018 (a) Based on Quoted Prices in Active Markets Other Observable Inputs Unobservable Inputs Assets Master Trust assets Money market funds $ 0.3 $ 0.3 $ — $ — Equity securities 3.8 — 3.8 — Debt securities 4.2 — 4.2 — Hedge funds 0.2 — 0.2 — Tangible assets 0.1 — 0.1 — Total Master Trust assets 8.6 0.3 8.3 — Derivative assets Interest rate hedges 1.9 — 1.9 — Total derivative assets 1.9 — 1.9 — Total assets $ 10.5 $ 0.3 $ 10.2 $ — Liabilities Long-term debt $ 597.2 $ — $ 579.4 $ 17.8 Total liabilities $ 597.2 $ — $ 579.4 $ 17.8 (a) Includes credit valuation adjustment Assets and Liabilities at Fair Value Level 1 Level 2 Level 3 $ in millions Fair value at December 31, 2017 (a) Based on Quoted Prices in Active Markets Other Observable Inputs Unobservable Inputs Assets Master Trust assets Money market funds $ 0.3 $ 0.3 $ — $ — Equity securities 4.2 — 4.2 — Debt securities 4.3 — 4.3 — Hedge funds 0.2 — 0.2 — Tangible assets 0.1 — 0.1 — Total Master Trust assets 9.1 0.3 8.8 — Derivative assets Interest rate hedges 1.8 — 1.8 — Total Derivative assets 1.8 — 1.8 — Total assets $ 10.9 $ 0.3 $ 10.6 $ — Liabilities Long-term debt $ 658.4 $ — $ 640.6 $ 17.8 Total liabilities $ 658.4 $ — $ 640.6 $ 17.8 (a) Includes credit valuation adjustment

Derivative Instruments and He32

Derivative Instruments and Hedging Activities (Tables)	3 Months Ended
	Mar. 31, 2018
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Schedule of Notional Amounts of Outstanding Derivative Positions	At March 31, 2018 , DPL's derivative instruments were as follows: Commodity Accounting Treatment (a) Unit Purchases Sales Net Purchases/ (Sales) FTRs Not designated MWh 0.1 — 0.1 Forward power contracts Not designated MWh 73.2 — 73.2 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 derivative instruments were as follows: Commodity Accounting Treatment (a) Unit Purchases Sales Net Purchases/ (Sales) FTRs Not designated MWh 2.1 — 2.1 Natural gas futures Not designated Dths 3,322.5 (390.0 ) 2,932.5 Forward power contracts Designated MWh 678.5 (1,667.0 ) (988.5 ) Forward power contracts Not designated MWh 871.0 (765.6 ) 105.4 Interest rate swaps Designated USD $ 200,000.0 $ — $ 200,000.0 (a) Refers to whether the derivative instruments have been designated as a cash flow hedge.
Gains or Losses Recognized in AOCI for the Cash Flow Hedges	The following tables provide information concerning gains or losses recognized in AOCI for the cash flow hedges for the three months ended March 31, 2018 and 2017 : Three months ended Three months ended March 31, 2018 March 31, 2017 Interest Interest $ in millions (net of tax) Power Rate Hedge Power Rate Hedge Beginning accumulated derivative gains / (losses) in AOCI $ (2.8 ) $ 17.5 $ (4.3 ) $ 17.4 Net gains associated with current period hedging transactions — 0.9 4.9 0.3 Net gains / (losses) reclassified to earnings Interest expense — (0.4 ) — (0.2 ) Revenues 4.1 — (0.9 ) — Purchased power (1.4 ) — 2.1 — Ending accumulated derivative gains / (losses) in AOCI $ (0.1 ) $ 18.0 $ 1.8 $ 17.5 Portion expected to be reclassified to earnings in the next twelve months (a) $ — $ (0.4 ) Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) 0 29 (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 present the amount and classification within the Condensed Consolidated Statements of Operations of the gains and losses on DPL’s derivatives not designated as hedging instruments for the three months ended March 31, 2018 and 2017 : For the three months ended March 31, 2018 $ in millions FTRs Power Natural Gas Total Change in unrealized gain / (loss) $ 0.2 $ (0.1 ) $ (0.1 ) $ — Realized gain / (loss) 0.2 (0.2 ) 0.2 0.2 Total $ 0.4 $ (0.3 ) $ 0.1 $ 0.2 Recorded in Income Statement: gain / (loss) Revenues $ — $ (1.5 ) $ — $ (1.5 ) Purchased power 0.4 1.2 0.1 1.7 Total $ 0.4 $ (0.3 ) $ 0.1 $ 0.2 For the three months ended March 31, 2017 $ in millions FTRs Power Natural Gas Total Change in unrealized gain / (loss) $ — $ (0.1 ) $ (0.1 ) $ (0.2 ) Realized gain / (loss) 0.2 (2.6 ) (0.2 ) (2.6 ) Total $ 0.2 $ (2.7 ) $ (0.3 ) $ (2.8 ) Recorded in Income Statement: gain / (loss) Revenues $ — $ (6.7 ) $ — $ (6.7 ) Purchased power 0.2 4.0 (0.3 ) 3.9 Total $ 0.2 $ (2.7 ) $ (0.3 ) $ (2.8 )
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value	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 at March 31, 2018 Gross Amounts Not Offset in the Condensed 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 Fair Value Assets Short-term derivative positions (presented in Other prepayments and current assets) Interest rate swap Designated $ 0.5 $ — $ — $ 0.5 Long-term derivative positions (presented in Other deferred assets) Interest rate swap Designated 1.4 — — 1.4 Total assets $ 1.9 $ — $ — $ 1.9 Liabilities Short-term derivative positions (presented in Other current liabilities) Forward power contracts Not designated 0.1 — (0.1 ) — FTRs Not designated 0.1 — — 0.1 Total liabilities $ 0.2 $ — $ (0.1 ) $ 0.1 (a) includes credit valuation adjustment Fair Values of Derivative Instruments at December 31, 2017 Gross Amounts Not Offset in the Condensed 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 Fair Value Assets Short-term derivative positions (presented in Other prepayments and current assets) 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 1.8 — — 1.8 Forward power contracts Not designated 0.6 — — 0.6 Total assets $ 12.8 $ (8.7 ) $ — $ 4.1 Liabilities Short-term derivative positions (presented in Other current liabilities) Forward power contracts Designated $ 9.0 $ (4.9 ) $ (1.4 ) $ 2.7 Forward power contracts Not designated 5.9 (3.7 ) — 2.2 FTRs Not designated 0.3 — — 0.3 Natural gas Not designated 0.1 (0.1 ) — — 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 Disclosures [Line Items]
Gains or Losses Recognized in AOCI for the Cash Flow Hedges	The following tables provide information concerning gains or losses recognized in AOCI for the cash flow hedges for the three months ended March 31, 2018 and 2017 : Three months ended Three months ended March 31, 2018 March 31, 2017 Interest Interest $ in millions (net of tax) Power Rate Hedge Power Rate Hedge Beginning accumulated derivative gains / (losses) in AOCI $ — $ 1.4 $ (4.3 ) $ 1.6 Net gains associated with current period hedging transactions — 0.5 — 0.3 Net gains / (losses) reclassified to earnings Interest expense — (0.3 ) — (0.2 ) Loss from discontinued operations — — 6.1 — Ending accumulated derivative gains in AOCI $ — $ 1.6 $ 1.8 $ 1.7 Portion expected to be reclassified to earnings in the next twelve months (a) $ — $ (0.3 ) Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) 0 29 (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	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: Hedging Designation Balance sheet classification March 31, 2018 December 31, 2017 Interest Rate Hedges in an Asset Position Cash Flow Hedge Other Deferred Assets Gross Fair Value as presented in the Balance Sheets $ 1.9 $ 1.8 Any ineffectiveness on the interest rate hedges and the monthly settlement of the interest rate hedges is recorded in interest expense within the Condensed Statements of Operations.

Debt (Tables)

Debt (Tables)	3 Months Ended
	Mar. 31, 2018
Debt Instrument [Line Items]
Long-term Debt	Interest March 31, December 31, $ in millions Rate Maturity 2018 2017 Term loan - rates from 3.57% - 4.82% (a) and 4.01% - 4.60% (b) 2022 $ 439.4 $ 440.6 Tax-exempt First Mortgage Bonds - rates from 2.50% - 2.58% (a) and 1.52% - 1.92% (b) 2020 140.0 200.0 U.S. Government note 4.2% 2061 17.8 17.8 Unamortized deferred financing costs (7.8 ) (9.8 ) Unamortized long-term debt discounts and premiums, net (1.7 ) (2.0 ) Total long-term debt at consolidated subsidiary 587.7 646.6 Bank term loan - rates from 3.82% - 3.90% (a) and 3.02% - 4.10% (b) 2020 — 70.0 Senior unsecured notes 6.75% 2019 200.0 200.0 Senior unsecured notes 7.25% 2021 780.0 780.0 Note to DPL Capital Trust II (c) 8.125% 2031 15.6 15.6 Capital leases — 0.2 Unamortized deferred financing costs (6.2 ) (6.8 ) Unamortized long-term debt discounts and premiums, net (0.5 ) (0.5 ) Total long-term debt 1,576.6 1,705.1 Less: current portion (105.6 ) (4.7 ) Long-term debt, net of current portion $ 1,471.0 $ 1,700.4 (a) Range of interest rates for the three months ended March 31, 2018 . (b) Range of interest rates for the year ended December 31, 2017 . (c) Note payable to related party.
THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Long-term Debt	The following table summarizes DP&L's outstanding long-term debt. Interest March 31, December 31, $ in millions Rate Maturity 2018 2017 Term loan - rates from 3.57% - 4.82% (a) and 4.01% - 4.60% (b) 2022 $ 439.4 $ 440.6 Tax-exempt First Mortgage Bonds - rates from 2.50% - 2.58% (a) and 1.52% - 1.92% (b) 2020 140.0 200.0 U.S. Government note 4.2% 2061 17.8 17.8 Unamortized deferred financing costs (7.8 ) (9.8 ) Unamortized long-term debt discounts (1.7 ) (2.0 ) Total long-term debt 587.7 646.6 Less: current portion (4.6 ) (4.6 ) Long-term debt, net of current portion $ 583.1 $ 642.0 (a) Range of interest rates for the three months ended March 31, 2018 . (b) Range of interest rates for the year ended December 31, 2017 .

Income Taxes (Tables)

Income Taxes (Tables)	3 Months Ended
	Mar. 31, 2018
Entity Information [Line Items]
Schedule of Effective Income Tax Rates	The following table details the effective tax rates for the three months ended March 31, 2018 and 2017 . Three months ended March 31, 2018 2017 DPL 17.6% 37.9%
THE DAYTON POWER AND LIGHT COMPANY [Member]
Entity Information [Line Items]
Schedule of Effective Income Tax Rates	The following table details the effective tax rates for the three months ended March 31, 2018 and 2017 . Three months ended March 31, 2018 2017 DP&L 18.7% 32.0%

Benefit Plans (Tables)

Benefit Plans (Tables)	3 Months Ended
	Mar. 31, 2018
Entity Information [Line Items]
Schedule of Net Periodic Benefit Cost / (Income)	The net periodic benefit cost of the pension benefit plans for the three months ended March 31, 2018 and 2017 was: Three months ended March 31, $ in millions 2018 2017 Service cost $ 1.5 $ 1.4 Interest cost 3.4 3.6 Expected return on plan assets (5.2 ) (5.7 ) Plan curtailment (a) — 4.1 Amortization of unrecognized: Prior service cost 0.2 0.4 Actuarial loss 1.6 1.3 Net periodic benefit cost $ 1.5 $ 5.1 (a) As a result of the decision to retire certain of DP&L's coal-fired plants, we recognized a plan curtailment of $4.1 million in the first quarter of 2017. See Note 15 – Fixed-asset Impairments for more information.
Estimated Future Benefit Payments and Medicare Part D Reimbursements	Benefit payments, which reflect future service, are estimated to be paid as follows: $ in millions Estimated balance to be paid during Pension 2018 $ 21.3 2019 $ 28.2 2020 $ 27.9 2021 $ 27.6 2022 $ 27.3 2023 - 2027 $ 131.3
THE DAYTON POWER AND LIGHT COMPANY [Member]
Entity Information [Line Items]
Schedule of Net Periodic Benefit Cost / (Income)	The net periodic benefit cost of the pension benefit plans for the three months ended March 31, 2018 and 2017 was: Three months ended March 31, $ in millions 2018 2017 Service cost $ 1.5 $ 1.4 Interest cost 3.4 3.6 Expected return on plan assets (5.2 ) (5.7 ) Plan curtailment (a) — 5.6 Amortization of unrecognized: Prior service cost 0.4 0.5 Actuarial loss 2.3 2.2 Net periodic benefit cost $ 2.4 $ 7.6 (a) As a result of the decision to retire certain of DP&L's coal-fired plants, we recognized a plan curtailment of $5.6 million in the first quarter of 2017.
Estimated Future Benefit Payments and Medicare Part D Reimbursements	Benefit payments, which reflect future service, are estimated to be paid as follows: $ in millions Estimated balance to be paid during Pension 2018 $ 21.3 2019 $ 28.2 2020 $ 27.9 2021 $ 27.6 2022 $ 27.3 2023 - 2027 $ 131.3

Business Segments (Tables)

Business Segments (Tables)	3 Months Ended
	Mar. 31, 2018
Segment Reporting Information [Line Items]
Financial Reporting for Reportable Business Segments

Revenue (Tables)

Revenue (Tables)	3 Months Ended
	Mar. 31, 2018
Disaggregation of Revenue [Table Text Block]	. The following table presents our revenue from contracts with customers and other revenue by segment during the period ended March 31, 2018 : $ in millions T&D Generation Other Adjustments and Eliminations Total Retail Revenue Retail revenue from contracts with customers $ 161.2 $ — $ — $ (0.2 ) $ 161.0 Other retail revenues (a) 9.2 — — — — — 9.2 Wholesale Revenue Wholesale revenue from contracts with customers 12.6 72.2 — — 84.8 Derivative losses (b) — (6.3 ) — — (6.3 ) RTO revenue 11.1 1.8 — — 12.9 RTO capacity revenues 1.9 27.3 — — 29.2 Other revenues from contracts with customers (c) — — 2.4 — 2.4 Other revenues — — 0.6 (0.6 ) — Total revenues $ 196.0 $ 95.0 $ 3.0 $ (0.8 ) $ 293.2 (a) Other retail revenue primarily includes alternative revenue programs not accounted for under ASC 606. Accounts receivable balances associated with these revenues were $3.1 million as of March 31, 2018 . (b) Derivative gains and losses are not accounted for under ASC 606. As of March 31, 2018 , accounts receivable balances associated with derivatives were $1.7 million . (c) Other revenues from contracts with customers primarily includes revenues for various services provided by Miami Valley Lighting.
Subsidiaries [Member]
Disaggregation of Revenue [Table Text Block]	. The following table presents our revenue from contracts with customers and other revenue during the period ended March 31, 2018 : $ in millions DP&L Total Retail Revenue Retail revenue from contracts with customers $ 161.2 Other retail revenues (a) 9.2 Wholesale Revenue Wholesale revenue from contracts with customers 12.6 RTO revenue 11.1 RTO capacity revenues 1.9 Total revenues $ 196.0 (a) Other retail revenue primarily includes alternative revenue programs not accounted for under ASC 606. Accounts receivable balances associated with these revenues were $3.1 million as of March 31, 2018 .

Generation Separation (Tables)

Generation Separation (Tables)	3 Months Ended
	Mar. 31, 2018
Subsidiaries [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Groups, Including Discontinued Operations [Table Text Block]	The following table summarizes the revenues, cost of revenues, operating and other expenses and income tax of discontinued operations for the period indicated: Three months ended March 31, 2017 Revenues $ 121.0 Cost of revenues (69.8 ) Operating and other expenses (73.6 ) Fixed-asset impairment (66.3 ) Loss from discontinued operations (88.7 ) Income tax benefit from discontinued operations (29.9 ) Net loss from discontinued operations $ (58.8 )

Held for Sale (Tables)

Held for Sale (Tables)	3 Months Ended
	Mar. 31, 2018
Subsidiaries [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Groups, Including Discontinued Operations [Table Text Block]	The following table summarizes the revenues, cost of revenues, operating and other expenses and income tax of discontinued operations for the period indicated: Three months ended March 31, 2017 Revenues $ 121.0 Cost of revenues (69.8 ) Operating and other expenses (73.6 ) Fixed-asset impairment (66.3 ) Loss from discontinued operations (88.7 ) Income tax benefit from discontinued operations (29.9 ) Net loss from discontinued operations $ (58.8 )

Summary of Significant Accoun40

Summary of Significant Accounting Policies (Narrative) (Details) $ in Millions	Jan. 01, 2018USD ($)	Mar. 31, 2018USD ($)mi²employeecustomergenerating_facilitysegment	Mar. 31, 2017USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Significant Accounting Policies [Line Items]
Number of reportable segments | segment		2
Cash and Cash Equivalents, at Carrying Value		$ 123.9		$ 24.5
Entity number of employees | employee		1,051
Employees under a collective bargaining agreement which expires in October-2011		59.00%
Excise taxes collected		$ 13.1	$ 12.5
Restricted Cash and Cash Equivalents, Current		27.4		1.9
Restricted Cash and Cash Equivalents		151.3	62.7	26.4	$ 83.6
AOCI reclassed to Retained Earnings before tax		1.6
AOCI reclassed to Retained Earnings, net of tax		$ (1)
THE DAYTON POWER AND LIGHT COMPANY [Member]
Significant Accounting Policies [Line Items]
Number of reportable segments | segment		1
Cash and Cash Equivalents, at Carrying Value		$ 1		5.2
Approximate number of retail customers | customer		523,000
Service area, square miles | mi²		6,000
Number of Operating Segments | segment		2
Entity number of employees | employee		673
Employees under a collective bargaining agreement which expires in October-2011		53.00%
Number Of Generating Facilities | generating_facility		3
Excise taxes collected		$ 13.1	12.5
Restricted Cash and Cash Equivalents, Current		0.9		0.4
Restricted Cash and Cash Equivalents		1.9	13.3	$ 5.6	$ 30.6
AOCI reclassed to Retained Earnings before tax	$ 1.7
AOCI reclassed to Retained Earnings, net of tax	$ 1.1	(1.1)	0
Adjustments for New Accounting Pronouncement [Member]
Significant Accounting Policies [Line Items]
AOCI reclassed to Retained Earnings before tax		1.6
AOCI reclassed to Retained Earnings, net of tax		1
Non-service Pension Costs			3.6
Increase (Decrease) in Restricted Cash			20.6
Adjustments for New Accounting Pronouncement [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Significant Accounting Policies [Line Items]
AOCI reclassed to Retained Earnings before tax		1.7
AOCI reclassed to Retained Earnings, net of tax		$ 1.1
Non-service Pension Costs			0.8
Increase (Decrease) in Restricted Cash			$ 20.6

Supplemental Financial Inform41

Supplemental Financial Information (Supplemental Financial Information) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Supplemental Financial Information [Line Items]
Gain (Loss) on Disposition of Business	$ (13.6)	$ 0
Gain (Loss) on Sale of Assets and Asset Impairment Charges	(0.6)	(19.4)
Unbilled revenue	12.1		$ 18
Customer receivables	65.7		57.8
Amounts due from partners in jointly owned stations	13.6		19.1
Other	10.9		4.9
Provision for uncollectible accounts	(1.1)		(1.1)
Total accounts receivable, net	101.2		98.7
Fuel and limestone	13.3		15.5
Plant materials and supplies	8.4		8.5
Other	0.6		0.5
Total inventories, at average cost	22.3		24.5
Other Operating Income (Expense), Net	(14.9)	(18.2)
THE DAYTON POWER AND LIGHT COMPANY [Member]
Supplemental Financial Information [Line Items]
Gain (Loss) on Disposition of Business	(12.4)	0
Gain (Loss) on Sale of Assets and Asset Impairment Charges	0	(19.4)
Unbilled revenue	12.1		18
Customer receivables	49.8		44.2
Amounts due from partners in jointly owned stations	3.8		0
Amounts due from affiliates	2.1		5
Other	6.3		4.7
Provision for uncollectible accounts	(1.1)		(1.1)
Total accounts receivable, net	73		70.8
Plant materials and supplies	7		6.9
Other	0.6		0.4
Total inventories, at average cost	7.6		$ 7.3
Other Operating Income (Expense), Net	(12.4)	0
Other Operating Income (Expense) [Member]
Supplemental Financial Information [Line Items]
Gain (Loss) on Disposition of Business	13.6	0
Insurance Recoveries	0	(1.2)
Gain (Loss) on Sale of Assets and Asset Impairment Charges	0.6	19.4
Other Cost and Expense, Operating	0.7	0
Other Operating Income (Expense), Net	14.9	$ 18.2
AES Ohio Generation peakers [Member]
Supplemental Financial Information [Line Items]
Gain (Loss) on Disposition of Business	$ 1.9

Supplemental Financial Inform42

Supplemental Financial Information (Reclassification out of ACOI) (Details) - USD ($) $ in Millions	Jan. 01, 2018	Mar. 31, 2018	Mar. 31, 2017
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Other income		$ (28.6)	$ (31.5)
AOCI reclassed to Retained Earnings before tax		1.6
Tax expense		(3.6)	31.5
Net loss		16.9	(51.7)
Interest expense		(28)	(27.3)
Revenue		293.2	323.9
Purchased power		(97.8)	(102)
Operating Expenses		(112.5)	(219.5)
THE DAYTON POWER AND LIGHT COMPANY [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Other income		(9.5)	(9)
AOCI reclassed to Retained Earnings before tax	$ 1.7
Tax expense		(3.6)	(8)
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax		0	(88.7)
Discontinued Operation, Tax Effect of Discontinued Operation		0	29.9
Net loss		15.7	(41.8)
Interest expense		(8.2)	(7.6)
Revenue		196	190.1
Purchased power		(83.8)	(81.1)
Operating Expenses		(82.5)	(75)
Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Net loss		1.4	1.7
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 loss		(0.5)	3.4
Gains / (losses) on available-for-sale securities [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Other income		0	(0.1)
AOCI reclassed to Retained Earnings before tax		(1.6)	0
Tax expense		0.6	0
Net loss		(1)	(0.1)
Gains / (losses) on available-for-sale securities [Member] | 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]
Other income		0	(0.1)
AOCI reclassed to Retained Earnings before tax		(1.7)	0
Tax expense		0.6	0
Net loss		(1.1)	(0.1)
Gains / (losses) on cash flow hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Tax expense		(0.8)	(0.5)
Net loss		2.3	1
Interest expense		(1.1)	(0.3)
Revenue		(2)	(1.5)
Purchased power		6.2	3.3
Total before income taxes		3.1	1.5
Gains / (losses) on cash flow hedges [Member] | 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]
Tax expense		0.5	0.1
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax		0	1.8
Discontinued Operation, Tax Effect of Discontinued Operation		0	(0.6)
Net loss		(0.3)	1
Interest expense		(0.8)	(0.3)
Amortization of defined benefit pension items [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Tax expense		(0.1)	(0.5)
Net loss		0.1	0.8
Operating Expenses		0.2	1.3
Amortization of defined benefit pension items [Member] | 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]
Tax expense		(0.2)	(1.3)
Net loss		0.9	2.5
Operating Expenses		$ 1.1	$ 3.8

Supplemental Financial Inform43

Supplemental Financial Information (Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions	Jan. 01, 2018	Mar. 31, 2018	Mar. 31, 2017
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	$ 0.8	$ 0.8
Other comprehensive loss before reclassifications		0.9
Amounts reclassified from accumulated other comprehensive income / (loss)		2.4
AOCI reclassed to Retained Earnings, net of tax		(1)
Other comprehensive income		2.3	$ 5.6
Balance, end of period		3.1
THE DAYTON POWER AND LIGHT COMPANY [Member]
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	(36.2)	(36.2)
Other comprehensive loss before reclassifications		0.5
Amounts reclassified from accumulated other comprehensive income / (loss)		0.6
AOCI reclassed to Retained Earnings, net of tax	1.1	(1.1)	0
Other comprehensive income		0	7.2
Balance, end of period		(36.2)
Gains / (losses) on available-for-sale securities [Member]
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	1	1
Other comprehensive loss before reclassifications		0
Amounts reclassified from accumulated other comprehensive income / (loss)		0
AOCI reclassed to Retained Earnings, net of tax		(1)	$ 0
Other comprehensive income		(1)
Balance, end of period		0
Gains / (losses) on available-for-sale securities [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
Other comprehensive loss before reclassifications		0
Amounts reclassified from accumulated other comprehensive income / (loss)		0
AOCI reclassed to Retained Earnings, net of tax		(1.1)
Other comprehensive income		(1.1)
Balance, end of period		0
Gains / (losses) on cash flow hedges [Member]
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	14.7	14.7
Other comprehensive loss before reclassifications		0.9
Amounts reclassified from accumulated other comprehensive income / (loss)		2.3
AOCI reclassed to Retained Earnings, net of tax		0
Other comprehensive income		3.2
Balance, end of period		17.9
Gains / (losses) on cash flow hedges [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
Other comprehensive loss before reclassifications		0.5
Amounts reclassified from accumulated other comprehensive income / (loss)		(0.3)
AOCI reclassed to Retained Earnings, net of tax		0
Other comprehensive income		0.2
Balance, end of period		1.6
Change in unfunded pension obligation [Member]
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	(14.9)	(14.9)
Other comprehensive loss before reclassifications		0
Amounts reclassified from accumulated other comprehensive income / (loss)		0.1
AOCI reclassed to Retained Earnings, net of tax		0
Other comprehensive income		0.1
Balance, end of period		(14.8)
Change in unfunded pension obligation [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)
Other comprehensive loss before reclassifications		0
Amounts reclassified from accumulated other comprehensive income / (loss)		0.9
AOCI reclassed to Retained Earnings, net of tax		0
Other comprehensive income		0.9
Balance, end of period		$ (37.8)

Regulatory Matters (Details)

Regulatory Matters (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 65.8
Public Utilities, Requested Rate Increase (Decrease), Percentage	4.00%
Subsidiaries [Member]
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 65.8
Public Utilities, Requested Rate Increase (Decrease), Percentage	4.00%

Property, Plant and Equipment45

Property, Plant and Equipment (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)generating_facilitypower_plantMW	Mar. 31, 2017USD ($)	Dec. 31, 2017USD ($)
Property, Plant and Equipment [Line Items]
Asset Retirement Obligations, Noncurrent	$ 128.3		$ 131.2
Asset Retirement Obligation, Accretion Expense	0.7
Asset Retirement Obligation, Liabilities Settled	(0.2)
Asset Retirement Obligation, Reductions Due to Plant Sales	(3.4)
Gain (Loss) on Sale of Assets and Asset Impairment Charges	(0.6)	$ (19.4)
Electric Transmission [Member] | Dpandl Investment [Member]
Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	0
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	39.4
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	9
Total Jointly Owned Stations [Member] | Dpandl Investment [Member]
Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	2.3
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	51.3
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	$ 20.5
Total Jointly Owned Stations [Member] | Dpandl Share [Member]
Property, Plant and Equipment [Line Items]
Production Plan Capacity | MW	1,137
Conesville Unit Four [Member] | Dpandl Investment [Member]
Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	$ 2.3
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	0.6
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	$ 0.6
Conesville Unit Four [Member] | Dpandl Share [Member]
Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	16.50%
Killen Station [Member] | Dpandl Investment [Member]
Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	$ 0
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	9.5
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	$ 9.1
Killen Station [Member] | Dpandl Share [Member]
Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	67.00%
Stuart Station [Member] | Dpandl Investment [Member]
Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	$ 0
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	1.8
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	$ 1.8
Stuart Station [Member] | Dpandl Share [Member]
Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	35.00%
Subsidiaries [Member]
Property, Plant and Equipment [Line Items]
Number Of Coal Fired Power Plants | power_plant	3
Asset Retirement Obligation	$ 4.7		$ 8
Asset Retirement Obligation, Revision of Estimate	$ 0.1
Number Of Generating Facilities | generating_facility	3
Asset Retirement Obligation, Reductions Due to Plant Sales	$ (3.4)
Gain (Loss) on Sale of Assets and Asset Impairment Charges	$ 0	$ (19.4)
Subsidiaries [Member] | Conesville Unit Four [Member] | Dpandl Share [Member]
Property, Plant and Equipment [Line Items]
Production Plan Capacity | MW	129
Subsidiaries [Member] | Killen Station [Member] | Dpandl Share [Member]
Property, Plant and Equipment [Line Items]
Production Plan Capacity | MW	402
Subsidiaries [Member] | Stuart Station [Member] | Dpandl Share [Member]
Property, Plant and Equipment [Line Items]
Production Plan Capacity | MW	606

Fair Value (Narrative) (Details

Fair Value (Narrative) (Details) - USD ($) $ in Millions	Jan. 01, 2018	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
AOCI reclassed to Retained Earnings before tax		$ 1.6
AOCI reclassed to Retained Earnings, net of tax		$ 1
Long-term debt, earliest maturities		2,019
Long-term debt, latest maturities		2,061
Unrealized Gains and Immaterial Unrealized Losses in AOCI, Before Tax				$ 1.6
Unrealized gains and immaterial unrealized losses in AOCI, after tax				1
Percent of inputs to the fair value of derivative instruments from quoted market prices (percent)		94.00%
THE DAYTON POWER AND LIGHT COMPANY [Member]
AOCI reclassed to Retained Earnings before tax	$ 1.7
AOCI reclassed to Retained Earnings, net of tax	$ (1.1)	$ 1.1	$ 0
Long-term debt, earliest maturities		2,020
Long-term debt, latest maturities		2,061
Unrealized Gains and Immaterial Unrealized Losses in AOCI, Before Tax				1.7
Unrealized gains and immaterial unrealized losses in AOCI, after tax				$ 1.1
Percent of inputs to the fair value of derivative instruments from quoted market prices (percent)		100.00%

Fair Value (Fair Value and Cost

Fair Value (Fair Value and Cost of Non-Derivative Instruments) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Mar. 31, 2018
Unrealized Gains and Immaterial Unrealized Losses in AOCI, Before Tax	$ 1.6
THE DAYTON POWER AND LIGHT COMPANY [Member]
Unrealized Gains and Immaterial Unrealized Losses in AOCI, Before Tax	1.7
Cost [Member]
Total Assets	7.3	$ 7.2
Cost [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Assets	7.3	7.2
Fair Value [Member]
Total Master Trust Assets, Fair Value	9.1	8.6
Total Assets	9.1	8.6
Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	9.1	8.6
Total Assets	9.1	8.6
Money Market Funds [Member] | Cost [Member]
Total Master Trust Assets, Cost	0.3	0.3
Money Market Funds [Member] | Cost [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Cost	0.3	0.3
Money Market Funds [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	0.3	0.3
Money Market Funds [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.3	0.3
Equity Securities [Member] | Cost [Member]
Total Master Trust Assets, Cost	2.5	2.4
Equity Securities [Member] | Cost [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Cost	2.5	2.4
Equity Securities [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	4.2	3.8
Equity Securities [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	4.2	3.8
Debt Securities [Member] | Cost [Member]
Total Master Trust Assets, Cost	4.3	4.3
Debt Securities [Member] | Cost [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Cost	4.3	4.3
Debt Securities [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	4.3	4.2
Debt Securities [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	4.3	4.2
Hedge Funds [Member] | Cost [Member]
Total Master Trust Assets, Cost	0.1	0.1
Hedge Funds [Member] | Cost [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Cost	0.1	0.1
Hedge Funds [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	0.2	0.2
Hedge Funds [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.2	0.2
Real Estate Funds [Member] | Cost [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Cost	0	0
Real Estate Funds [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0	0
Tangible Assets [Member] | Cost [Member]
Total Master Trust Assets, Cost	0.1	0.1
Tangible Assets [Member] | Cost [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Cost	0.1	0.1
Tangible Assets [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	0.1	0.1
Tangible Assets [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.1	0.1
Debt [Member] | Cost [Member]
Debt, Cost	1,704.8	1,576.6
Debt [Member] | Cost [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt, Cost	646.6	587.7
Debt [Member] | Fair Value [Member]
Debt, Fair Value	1,819.3	1,661.4
Debt [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt, Fair Value	$ 658.4	$ 597.2

Fair Value (Fair Value of Asset

Fair Value (Fair Value of Assets and Liabilities Measured on Recurring Basis) (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Level 1 [Member]
Total Master Trust Assets, Fair Value	$ 0.3	$ 0.3
Total Derivative Assets	0	0.2
Total Assets	0.3	0.5
Total Derivative Liabilities	0	0.1
Total Liabilities	0	0.1
Level 1 [Member] | Commodity Contract - FTR [Member]
Total Derivative Assets		0.2
Total Derivative Liabilities	0	0
Level 1 [Member] | Forward Contract Power [Member]
Total Derivative Assets		0
Total Derivative Liabilities	0	0
Level 1 [Member] | Interest Rate Contract [Member]
Total Derivative Assets	0	0
Total Derivative Liabilities		0.1
Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.3	0.3
Total Derivative Assets	0	0
Total Assets	0.3	0.3
Total Liabilities	0	0
Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Interest Rate Contract [Member]
Total Derivative Assets	0	0
Level 2 [Member]
Total Master Trust Assets, Fair Value	8.3	8.8
Total Derivative Assets	1.9	12.6
Total Assets	10.2	21.4
Total Derivative Liabilities	0.1	14.9
Total Liabilities	1,643.7	1,816.4
Level 2 [Member] | Commodity Contract - FTR [Member]
Total Derivative Assets		0
Total Derivative Liabilities	0	0
Level 2 [Member] | Forward Contract Power [Member]
Total Derivative Assets		10.8
Total Derivative Liabilities	0.1	14.9
Level 2 [Member] | Interest Rate Contract [Member]
Total Derivative Assets	1.9	1.8
Total Derivative Liabilities		0
Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	8.3	8.8
Total Derivative Assets	1.9	1.8
Total Assets	10.2	10.6
Total Liabilities	579.4	640.6
Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Interest Rate Contract [Member]
Total Derivative Assets	1.9	1.8
Level 3 [Member]
Total Master Trust Assets, Fair Value	0	0
Total Derivative Assets	0	0
Total Assets	0	0
Total Derivative Liabilities	0.1	0.3
Total Liabilities	17.9	18.1
Level 3 [Member] | Commodity Contract - FTR [Member]
Total Derivative Assets		0
Total Derivative Liabilities	0.1	0.3
Level 3 [Member] | Forward Contract Power [Member]
Total Derivative Assets		0
Total Derivative Liabilities	0	0
Level 3 [Member] | Interest Rate Contract [Member]
Total Derivative Assets	0	0
Total Derivative Liabilities		0
Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0	0
Total Derivative Assets	0	0
Total Assets	0	0
Total Liabilities	17.8	17.8
Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Interest Rate Contract [Member]
Total Derivative Assets	0	0
Fair Value [Member]
Total Master Trust Assets, Fair Value	8.6	9.1
Total Derivative Assets	1.9	12.8
Total Assets	10.5	21.9
Total Derivative Liabilities	0.2	15.3
Total Liabilities	1,661.6	1,834.6
Fair Value [Member] | Commodity Contract - FTR [Member]
Total Derivative Assets		0.2
Total Derivative Liabilities	0.1	0.3
Fair Value [Member] | Forward Contract Power [Member]
Total Derivative Assets		10.8
Total Derivative Liabilities	0.1	14.9
Fair Value [Member] | Interest Rate Contract [Member]
Total Derivative Assets	1.9	1.8
Total Derivative Liabilities		0.1
Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	8.6	9.1
Total Derivative Assets	1.9	1.8
Total Assets	10.5	10.9
Total Liabilities	597.2	658.4
Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Interest Rate Contract [Member]
Total Derivative Assets	1.9	1.8
Money Market Funds [Member] | Level 1 [Member]
Total Master Trust Assets, Fair Value	0.3	0.3
Money Market Funds [Member] | Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.3	0.3
Money Market Funds [Member] | Level 2 [Member]
Total Master Trust Assets, Fair Value	0	0
Money Market Funds [Member] | Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0	0
Money Market Funds [Member] | Level 3 [Member]
Total Master Trust Assets, Fair Value	0	0
Money Market Funds [Member] | Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0	0
Money Market Funds [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	0.3	0.3
Money Market Funds [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.3	0.3
Equity Securities [Member] | Level 1 [Member]
Total Master Trust Assets, Fair Value	0	0
Equity Securities [Member] | Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0	0
Equity Securities [Member] | Level 2 [Member]
Total Master Trust Assets, Fair Value	3.8	4.2
Equity Securities [Member] | Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	3.8	4.2
Equity Securities [Member] | Level 3 [Member]
Total Master Trust Assets, Fair Value	0	0
Equity Securities [Member] | Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0	0
Equity Securities [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	3.8	4.2
Equity Securities [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	3.8	4.2
Debt Securities [Member] | Level 1 [Member]
Total Master Trust Assets, Fair Value	0	0
Debt Securities [Member] | Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0	0
Debt Securities [Member] | Level 2 [Member]
Total Master Trust Assets, Fair Value	4.2	4.3
Debt Securities [Member] | Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	4.2	4.3
Debt Securities [Member] | Level 3 [Member]
Total Master Trust Assets, Fair Value	0	0
Debt Securities [Member] | Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0	0
Debt Securities [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	4.2	4.3
Debt Securities [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	4.2	4.3
Hedge Funds [Member] | Level 1 [Member]
Total Master Trust Assets, Fair Value	0	0
Hedge Funds [Member] | Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0	0
Hedge Funds [Member] | Level 2 [Member]
Total Master Trust Assets, Fair Value	0.2	0.2
Hedge Funds [Member] | Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.2	0.2
Hedge Funds [Member] | Level 3 [Member]
Total Master Trust Assets, Fair Value	0	0
Hedge Funds [Member] | Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0	0
Hedge Funds [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	0.2	0.2
Hedge Funds [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.2	0.2
Real Estate Funds [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0	0
Tangible Assets [Member] | Level 1 [Member]
Total Master Trust Assets, Fair Value	0	0
Tangible Assets [Member] | Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0	0
Tangible Assets [Member] | Level 2 [Member]
Total Master Trust Assets, Fair Value	0.1	0.1
Tangible Assets [Member] | Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.1	0.1
Tangible Assets [Member] | Level 3 [Member]
Total Master Trust Assets, Fair Value	0	0
Tangible Assets [Member] | Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0	0
Tangible Assets [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	0.1	0.1
Tangible Assets [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.1	0.1
Debt [Member] | Level 1 [Member]
Debt	0	0
Debt [Member] | Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt	0	0
Debt [Member] | Level 2 [Member]
Debt	1,643.6	1,801.5
Debt [Member] | Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt	579.4	640.6
Debt [Member] | Level 3 [Member]
Debt	17.8	17.8
Debt [Member] | Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt	17.8	17.8
Debt [Member] | Fair Value [Member]
Debt	1,661.4	1,819.3
Debt [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt	$ 597.2	$ 658.4

Fair Value Fair Value Measureme

Fair Value Fair Value Measurements (Fair Value of Assets and Liabilities Measured on a Non-recurring Basis) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant and Equipment, Net	$ 1,330.4		$ 1,324.9
Impairment of Long-Lived Assets Held-for-use	0	$ 66.4
Asset Retirement Obligations, Noncurrent	128.3		131.2
Killen [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant and Equipment, Net		35.2
Impairment of Long-Lived Assets Held-for-use		27.3
Killen [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant, and Equipment, Fair Value Disclosure		0
Killen [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant, and Equipment, Fair Value Disclosure		0
Killen [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant, and Equipment, Fair Value Disclosure		7.9
Stuart [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant and Equipment, Net		42.4
Impairment of Long-Lived Assets Held-for-use		39.1
Stuart [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant, and Equipment, Fair Value Disclosure		0
Stuart [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant, and Equipment, Fair Value Disclosure		0
Stuart [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant, and Equipment, Fair Value Disclosure		3.3
THE DAYTON POWER AND LIGHT COMPANY [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset Retirement Obligation	4.7		8
Property, Plant and Equipment, Net	1,304.8		$ 1,301.4
Impairment of Long-Lived Assets Held-for-use	0	$ 66.3
Income Approach Valuation Technique [Member] | Weighted Average [Member] | Killen [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent		22.00%
Fair Value Inputs, Discount Rate		7.00%
Income Approach Valuation Technique [Member] | Weighted Average [Member] | Stuart [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent		10.00%
Fair Value Inputs, Discount Rate		7.00%
Ash ponds, asbestos, river structures and underground storage tanks [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Increase (Decrease) in Asset Retirement Obligations
Ash ponds, asbestos, river structures and underground storage tanks [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Increase (Decrease) in Asset Retirement Obligations	$ (3.3)	$ (2.9)

Derivative Instruments and He50

Derivative Instruments and Hedging Activities (Narrative) (Details)	3 Months Ended
	Mar. 31, 2018USD ($)Number_of_interest_rate_swaps	Mar. 29, 2018USD ($)	Dec. 31, 2017USD ($)
Sale of Derivative Instruments Interest Rate Swap		$ 60,000,000
THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument, Number of Financial Covenants | Number_of_interest_rate_swaps	2
Long-term Debt, Gross	$ 597,200,000
Sale of Derivative Instruments Interest Rate Swap		$ 60,000,000
One Point One Three To One Point One Seven Bonds Maturing In August Two Thousand Twenty [Member]
Long-term Debt, Gross	140,000,000
One Point One Three To One Point One Seven Bonds Maturing In August Two Thousand Twenty [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Long-term Debt, Gross	140,000,000
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 Expense	800,000
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Derivative, Notional Amount, Purchase (Sales), Net	140,000,000		$ 200,000,000
Interest Expense	$ 800,000

Derivative Instruments and He51

Derivative Instruments and Hedging Activities (Outstanding Derivative Instruments) (Details)	Mar. 31, 2018USD ($)MWh	Mar. 29, 2018USD ($)	Dec. 31, 2017USD ($)MMBTUMWh
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)
Not Designated as Hedging Instrument [Member] | Commodity Contract - FTR [Member]
Purchase of Units Derivative Instruments Financial Transmission Rights	100		2,100
Sale of Units Derivative Instruments Financial Transmission Rights	0		0
Derivative, Nonmonetary Notional Amount MWh	100		2,100
Not Designated as Hedging Instrument [Member] | Natural Gas [Member]
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]
Purchase of Units Derivative Instruments Forward Power Contracts Not Designated as Hedged	73,200		871,000
Sales of Units Derivative Instruments Forward Power Contracts Not Designated as Hedged	0		(765,600)
Derivative, Nonmonetary Notional Amount MWh	73,200		105,400
Designated as Hedging Instrument [Member] | Forward Contract Power [Member]
Purchase of Units Derivative Instruments Forward Power Contracts Designated as Cash Flow Hedge			678,500
Sales of Units Derivative Instruments Forward Power Contracts Designated as Cash Flow Hedge			(1,667,000)
Derivative, Nonmonetary Notional Amount MWh			(988,500)
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Purchase of Derivative Instruments Interest Rate Swap | $	$ 140,000,000		$ 200,000,000
Sale of Derivative Instruments Interest Rate Swap | $	0		0
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

Derivative Instruments and He52

Derivative Instruments and Hedging Activities (Gains or Losses Recognized in AOCI for the Cash Flow Hedges) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Forward Contract Power [Member]
Accumulated Derivative Gain/Loss in AOCI [Roll Forward]
Beginning accumulated derivative gain / (loss) in AOCI	$ (2.8)	$ (4.3)
Net gains / (losses) associated with current period hedging transactions	0	4.9
Ending accumulated derivative gain / (loss) in AOCI	(0.1)	1.8
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]
Accumulated Derivative Gain/Loss in AOCI [Roll Forward]
Beginning accumulated derivative gain / (loss) in AOCI	$ 17.5	17.4
Net gains / (losses) associated with current period hedging transactions	0.9	0.3
Ending accumulated derivative gain / (loss) in AOCI	18	17.5
Portion expected to be reclassified to earnings in the next twelve months	$ (0.4)
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)	29 months
THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member]
Accumulated Derivative Gain/Loss in AOCI [Roll Forward]
Beginning accumulated derivative gain / (loss) in AOCI	$ 0	(4.3)
Net gains / (losses) associated with current period hedging transactions	0	0
Ending accumulated derivative gain / (loss) in AOCI	0	1.8
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
THE DAYTON POWER AND LIGHT COMPANY [Member] | Interest Rate Contract [Member]
Accumulated Derivative Gain/Loss in AOCI [Roll Forward]
Beginning accumulated derivative gain / (loss) in AOCI	$ 1.4	1.6
Net gains / (losses) associated with current period hedging transactions	0.5	0.3
Ending accumulated derivative gain / (loss) in AOCI	1.6	1.7
Portion expected to be reclassified to earnings in the next twelve months	$ (0.3)
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)	29 months
Interest Expense [Member] | Forward Contract Power [Member]
Accumulated Derivative Gain/Loss in AOCI [Roll Forward]
Net gains losses reclassified to earnings	$ 0	0
Interest Expense [Member] | Interest Rate Contract [Member]
Accumulated Derivative Gain/Loss in AOCI [Roll Forward]
Net gains losses reclassified to earnings	(0.4)	(0.2)
Interest Expense [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member]
Accumulated Derivative Gain/Loss in AOCI [Roll Forward]
Net gains losses reclassified to earnings	0	0
Interest Expense [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Interest Rate Contract [Member]
Accumulated Derivative Gain/Loss in AOCI [Roll Forward]
Net gains losses reclassified to earnings	(0.3)	(0.2)
Discontinued Operations, Disposed of by Means Other than Sale, Spinoff [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member]
Accumulated Derivative Gain/Loss in AOCI [Roll Forward]
Net gains losses reclassified to earnings	0	6.1
Discontinued Operations, Disposed of by Means Other than Sale, Spinoff [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Interest Rate Contract [Member]
Accumulated Derivative Gain/Loss in AOCI [Roll Forward]
Net gains losses reclassified to earnings	0	0
Revenue [Member] | Forward Contract Power [Member]
Accumulated Derivative Gain/Loss in AOCI [Roll Forward]
Net gains losses reclassified to earnings	4.1	(0.9)
Revenue [Member] | Interest Rate Contract [Member]
Accumulated Derivative Gain/Loss in AOCI [Roll Forward]
Net gains losses reclassified to earnings	0	0
Purchased Power [Member] | Forward Contract Power [Member]
Accumulated Derivative Gain/Loss in AOCI [Roll Forward]
Net gains losses reclassified to earnings	(1.4)	2.1
Purchased Power [Member] | Interest Rate Contract [Member]
Accumulated Derivative Gain/Loss in AOCI [Roll Forward]
Net gains losses reclassified to earnings	$ 0	$ 0

Derivative Instruments and He53

Derivative Instruments and Hedging Activities (Classification within the Condensed Consolidated Statements of Results of Operations or Balance Sheets of the Gains and Losses) (Details) - Not Designated as Hedging Instrument [Member] - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Change in unrealized gain / (loss)	$ 0	$ (0.2)
Realized gain / (loss)	0.2	(2.6)
Derivative, Gain (Loss) on Derivative, Net	0.2	(2.8)
Commodity Contract - FTR [Member]
Change in unrealized gain / (loss)	0.2	0
Realized gain / (loss)	0.2	0.2
Derivative, Gain (Loss) on Derivative, Net	0.4	0.2
Forward Contract Power [Member]
Change in unrealized gain / (loss)	(0.1)	(0.1)
Realized gain / (loss)	(0.2)	(2.6)
Derivative, Gain (Loss) on Derivative, Net	(0.3)	(2.7)
Natural Gas [Member]
Change in unrealized gain / (loss)	(0.1)	(0.1)
Realized gain / (loss)	0.2	(0.2)
Derivative, Gain (Loss) on Derivative, Net	0.1	(0.3)
Revenue [Member]
Derivative, Gain (Loss) on Derivative, Net	(1.5)	(6.7)
Revenue [Member] | Commodity Contract - FTR [Member]
Derivative, Gain (Loss) on Derivative, Net	0	0
Revenue [Member] | Forward Contract Power [Member]
Derivative, Gain (Loss) on Derivative, Net	(1.5)	(6.7)
Revenue [Member] | Natural Gas [Member]
Derivative, Gain (Loss) on Derivative, Net	0	0
Purchased Power [Member]
Derivative, Gain (Loss) on Derivative, Net	1.7	3.9
Purchased Power [Member] | Commodity Contract - FTR [Member]
Derivative, Gain (Loss) on Derivative, Net	0.4	0.2
Purchased Power [Member] | Forward Contract Power [Member]
Derivative, Gain (Loss) on Derivative, Net	1.2	4
Purchased Power [Member] | Natural Gas [Member]
Derivative, Gain (Loss) on Derivative, Net	$ 0.1	$ (0.3)

Derivative Instruments and He54

Derivative Instruments and Hedging Activities (Fair Value and Balance Sheet Location (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Total Assets [Member]
Derivative Asset, Fair Value	$ 1.9	$ 12.8
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	1.9	4.1
Total Liabilities [Member]
Derivative Liability, Fair Value	0.2	15.3
Derivative, Collateral, Right to Reclaim Securities	0	(8.7)
Derivative, Collateral, Right to Reclaim Cash	(0.1)	(1.4)
Liability position offset by the asset position of counterparties with master netting agreements	0.1	5.2
Cash Flow Hedging [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Prepayments and Current Assets [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
Cash Flow Hedging [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member]
Derivative Liability, Fair Value		9
Derivative, Collateral, Right to Reclaim Securities		(4.9)
Derivative, Collateral, Right to Reclaim Cash		(1.4)
Liability position offset by the asset position of counterparties with master netting agreements		2.7
Cash Flow Hedging [Member] | Interest Rate Swap [Member] | Short-term Derivative Positions [Member] | Other Prepayments and Current Assets [Member]
Derivative Asset, Fair Value	0.5
Derivative, Collateral, Obligation to Return Securities	0
Derivative, Collateral, Obligation to Return Cash	0
Derivative Asset, Fair Value, Amount Offset Against Collateral	0.5
Cash Flow Hedging [Member] | Interest Rate Swap [Member] | Long-term Derivative Positions [Member] | Other Deferred Asset [Member]
Derivative Asset, Fair Value	1.4	1.8
Derivative, Collateral, Obligation to Return Securities	0	0
Derivative, Collateral, Obligation to Return Cash	0	0
Derivative Asset, Fair Value, Amount Offset Against Collateral	1.4	1.8
Fair Value Hedging [Member] | Commodity Contract - FTR [Member] | Short-term Derivative Positions [Member] | Other Prepayments and Current Assets [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
Fair Value Hedging [Member] | Commodity Contract - FTR [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member]
Derivative Liability, Fair Value	0.1	0.3
Derivative, Collateral, Right to Reclaim Securities	0	0
Derivative, Collateral, Right to Reclaim Cash	0	0
Liability position offset by the asset position of counterparties with master netting agreements	0.1	0.3
Fair Value Hedging [Member] | Natural Gas [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member]
Derivative Liability, Fair Value		0.1
Derivative, Collateral, Right to Reclaim Securities		(0.1)
Derivative, Collateral, Right to Reclaim Cash		0
Liability position offset by the asset position of counterparties with master netting agreements		0
Fair Value Hedging [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Prepayments and Current Assets [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
Fair Value Hedging [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member]
Derivative Liability, Fair Value	0.1	5.9
Derivative, Collateral, Right to Reclaim Securities	0	(3.7)
Derivative, Collateral, Right to Reclaim Cash	(0.1)	0
Liability position offset by the asset position of counterparties with master netting agreements	0	2.2
Fair Value Hedging [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Asset [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
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Other Deferred Asset [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Derivative Asset, Fair Value	$ 1.9	$ 1.8

Debt (Narrative) (Details)

Debt (Narrative) (Details)	3 Months Ended		6 Months Ended		12 Months Ended
	Mar. 31, 2018USD ($)fiscal_quarterdebt_covenant	Mar. 31, 2017USD ($)	Dec. 31, 2018	Jul. 03, 2018	Sep. 30, 2018USD ($)	Apr. 30, 2018USD ($)	Mar. 30, 2018USD ($)	Jan. 03, 2018	Dec. 31, 2017USD ($)	Aug. 03, 2015USD ($)
Debt Instrument [Line Items]
Long-term Line of Credit	$ 0
Retirement of long-term debt	$ 131,100,000	$ 7,400,000
Debt Covenant, Leverage Ratio, Maximum	0.67
Debt Covenant, Interest Coverage Ratio, Minimum	2.50
Leverage Ratio	1.47
Debt Covenant, Total Debt to Total Capitalization Ratio, Maximum	0.65
THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Long-term Line of Credit	$ 20,000,000
Long-term Debt, Gross	597,200,000
Retirement of long-term debt	$ 61,100,000	1,100,000
Long Term Indebtedness, Less than or Equal to		$ 750,000,000
Debt Covenant, Interest Coverage Ratio, Minimum	2.50
Debt Covenant, Total Debt to Total Capitalization Ratio, Maximum	0.65
Senior unsecured due in October 2019 - 6.75% [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount	$ 101,000,000
Long-term Debt, Gross	$ 200,000,000						$ 200,000,000		$ 200,000,000
Debt instrument interest percentage	6.75%
Variable Rate Notes Backed by Term Loan and First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount	$ 60,000,000
Variable Rate Notes Backed by Term Loan and First Mortgage Bonds [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount	60,000,000
Long-term Debt, Gross	140,000,000								200,000,000
Debt Instrument, Face Amount										$ 200,000,000
Bank term loan due in July 2020 - rates from: 2.44% - 2.45% [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount	70,000,000
Long-term Debt, Gross									70,000,000
Term Loan Maturing 2022 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	439,400,000								440,600,000
Term Loan Maturing 2022 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 439,400,000								$ 440,600,000
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 EBITDA to interest calculation | fiscal_quarter	4
DPL Revolving Credit Agreement and Term Loan Maturing July 2020 [Member]
Debt Instrument [Line Items]
Number of financial covenants | debt_covenant	2
Number of prior quarters included in EBITDA to interest calculation | fiscal_quarter	4
Number of prior quarters included in debt to EBITDA ratio | fiscal_quarter	4
Base Rate Term Loan B [Member]
Debt Instrument [Line Items]
Debt instrument interest percentage								1.00%	2.25%
Base Rate Term Loan B [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Debt instrument interest percentage								1.00%	2.25%
Eurodollar rate Term Loan B [Member]
Debt Instrument [Line Items]
Debt instrument interest percentage								2.00%	3.25%
Eurodollar rate Term Loan B [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Debt instrument interest percentage								2.00%	3.25%
Subsequent Event [Member]
Debt Instrument [Line Items]
Long Term Indebtedness, Less than or Equal to					$ 750,000,000
Debt Covenant, Total Debt to Total Capitalization Ratio, Maximum					0.75
Subsequent Event [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Long Term Indebtedness, Less than or Equal to					$ 750,000,000
Debt Covenant, Total Debt to Total Capitalization Ratio, Maximum					0.75
Subsequent Event [Member] | Senior unsecured due in October 2019 - 6.75% [Member]
Debt Instrument [Line Items]
Make Whole Premium						$ 5,100,000
Subsequent Event [Member] | Term Loan Maturing 2022 [Member]
Debt Instrument [Line Items]
Early prepayment rate				101.00%
Standard Repayment Rate			100.00%
Subsequent Event [Member] | 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%

Debt (Long-term Debt) (Details)

Debt (Long-term Debt) (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Mar. 31, 2018	Dec. 31, 2018	Jul. 03, 2018	Mar. 30, 2018	Dec. 31, 2017	Mar. 31, 2017
Debt Instrument [Line Items]
Capital Lease Obligations	$ 0				$ 0.2
Unamortized deferred finance costs	(7.8)				(9.8)
Unamortized deferred finance costs	(6.2)				(6.8)
Unamortized long-term debt discounts and premiums, net	(0.5)				(0.5)
Total long-term debt at subsidiary	587.7				646.6
Total long-term debt	1,576.6				1,705.1
Less: current portion	(105.6)				(4.7)
Long-term debt	$ 1,471				1,700.4
Long-term debt, earliest maturities	2,019
Long-term debt, latest maturities	2,061
THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 597.2
Unamortized deferred finance costs	(7.8)				(9.8)
Unamortized long-term debt discounts and premiums, net	(1.7)				(2)
Unamortized long-term debt discounts	(1.7)				(2)
Total long-term debt	587.7				646.6
Less: current portion	(4.6)				(4.6)
Long-term debt	$ 583.1				642
Long-term debt, earliest maturities	2,020
Long-term debt, latest maturities	2,061
Term Loan Maturing 2022 [Domain]
Debt Instrument [Line Items]
Debt instrument maturity year	Aug. 24, 2022
Term Loan Maturing 2022 [Domain] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Debt instrument maturity year	Aug. 24, 2022
Term Loan Maturing 2022 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 439.4				440.6
Term Loan Maturing 2022 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 439.4				440.6
Pollution Control Series Maturing in August 2020 - 1.13% - 1.14% [Member]
Debt Instrument [Line Items]
Debt instrument maturity year	Aug. 1, 2020
Pollution Control Series Maturing in August 2020 - 1.13% - 1.14% [Member] | 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 February 2061 - 4.20% [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 17.8				17.8
Debt instrument maturity year	Feb. 1, 2061
Debt instrument interest percentage	4.20%
U.S. Government note maturing in February 2061 - 4.20% [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 17.8				17.8
Debt instrument maturity year	Feb. 1, 2061
Debt instrument interest percentage	4.20%
Bank term loan due in July 2020 - rates from: 2.44% - 2.45% [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross					70
Debt instrument maturity year	Jul. 31, 2020
Senior unsecured due in October 2019 - 6.75% [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 200			$ 200	200
Debt instrument maturity year	Oct. 1, 2019
Debt instrument interest percentage	6.75%
Senior unsecured due in October 2021 - 7.25% [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 September 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%
Subsequent Event [Member] | Term Loan Maturing 2022 [Member]
Debt Instrument [Line Items]
Early prepayment rate			101.00%
Standard Repayment Rate		100.00%
Subsequent Event [Member] | 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%
Maximum [Member] | Term Loan Maturing 2022 [Member]
Debt Instrument [Line Items]
Debt instrument interest percentage	4.82%
Debt Instrument, Interest Rate, Effective Percentage						4.60%
Maximum [Member] | Term Loan Maturing 2022 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Debt instrument interest percentage	4.82%
Debt Instrument, Interest Rate, Effective Percentage						4.60%
Maximum [Member] | Pollution Control Series Maturing in August 2020 - 1.13% - 1.14% [Member]
Debt Instrument [Line Items]
Debt instrument interest percentage						1.92%
Maximum [Member] | Zero Point Two Three To Zero Point Two Nine And Zero Point One Six To Zero Point Three Six Percentage Of Bonds Maturing In November Two Thousand Forty [Member]
Debt Instrument [Line Items]
Debt instrument interest percentage	2.577%
Maximum [Member] | Zero Point Two Three To Zero Point Two Nine And Zero Point One Six To Zero Point Three Six Percentage Of Bonds Maturing In November Two Thousand Forty [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Debt instrument interest percentage	2.58%					1.92%
Maximum [Member] | Bank term loan due in July 2020 - rates from: 2.44% - 2.45% [Member]
Debt Instrument [Line Items]
Debt instrument interest percentage	3.898%					4.10%
Minimum [Member] | Term Loan Maturing 2022 [Member]
Debt Instrument [Line Items]
Debt instrument interest percentage						4.01%
Debt Instrument, Interest Rate, Effective Percentage	3.57%
Minimum [Member] | Term Loan Maturing 2022 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Debt instrument interest percentage						4.01%
Debt Instrument, Interest Rate, Effective Percentage	3.57%
Minimum [Member] | Pollution Control Series Maturing in August 2020 - 1.13% - 1.14% [Member]
Debt Instrument [Line Items]
Debt instrument interest percentage						1.52%
Minimum [Member] | Zero Point Two Three To Zero Point Two Nine And Zero Point One Six To Zero Point Three Six Percentage Of Bonds Maturing In November Two Thousand Forty [Member]
Debt Instrument [Line Items]
Debt instrument interest percentage	2.498%
Minimum [Member] | Zero Point Two Three To Zero Point Two Nine And Zero Point One Six To Zero Point Three Six Percentage Of Bonds Maturing In November Two Thousand Forty [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Debt instrument interest percentage	2.50%					1.52%
Minimum [Member] | Bank term loan due in July 2020 - rates from: 2.44% - 2.45% [Member]
Debt Instrument [Line Items]
Debt instrument interest percentage	3.817%					3.02%

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Entity Information [Line Items]
Effective income tax rates	17.60%	37.90%
Estimated annual effective income tax rate	19.20%	37.60%
Federal Income Tax Rate for Corporations	21.00%	35.00%
Non-cash capital contribution	$ 45.1	$ 0
THE DAYTON POWER AND LIGHT COMPANY [Member]
Entity Information [Line Items]
Effective income tax rates	18.70%	32.00%
Estimated annual effective income tax rate	19.80%	33.80%
Federal Income Tax Rate for Corporations	21.00%	35.00%

Benefit Plans (Net Periodic Ben

Benefit Plans (Net Periodic Benefit Cost (Income)) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Pension [Member]
Contributions by employer	$ 7.6	$ 5
Service cost	1.5	1.4
Interest cost	3.4	3.6
Expected return on assets	(5.2)	(5.7)
Defined Benefit Plan, Benefit Obligation, (Increase) Decrease for Curtailment	0	4.1
Prior service cost	0.2	0.4
Actuarial loss / (gain)	1.6	1.3
Net periodic benefit cost	1.5	5.1
Postretirement [Member]
Defined Benefit Plan, Funded (Unfunded) Status of Plan			$ 12.7
THE DAYTON POWER AND LIGHT COMPANY [Member] | Pension [Member]
Contributions by employer	7.6	5
Service cost	1.5	1.4
Interest cost	3.4	3.6
Expected return on assets	(5.2)	(5.7)
Defined Benefit Plan, Benefit Obligation, (Increase) Decrease for Curtailment	0	5.6
Prior service cost	0.4	0.5
Actuarial loss / (gain)	2.3	2.2
Net periodic benefit cost	$ 2.4	$ 7.6
THE DAYTON POWER AND LIGHT COMPANY [Member] | Postretirement [Member]
Defined Benefit Plan, Funded (Unfunded) Status of Plan			$ 12.7

Benefit Plans (Estimated Future

Benefit Plans (Estimated Future Benefit Payments and Medicare Part D Reimbursements) (Details) - Pension [Member] $ in Millions	Mar. 31, 2018USD ($)
2,016	$ 21.3
2,017	28.2
2,018	27.9
2,019	27.6
2,020	27.3
2021 - 2025	131.3
THE DAYTON POWER AND LIGHT COMPANY [Member]
2,016	21.3
2,017	28.2
2,018	27.9
2,019	27.6
2,020	27.3
2021 - 2025	$ 131.3

Shareholder's Equity (Details)

Shareholder's Equity (Details) - USD ($)	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Class of Stock [Line Items]
Non-cash capital contribution	$ 45,100,000	$ 0
Common stock, shares authorized	1,500		1,500
Common stock, shares outstanding	1		1
THE DAYTON POWER AND LIGHT COMPANY [Member]
Class of Stock [Line Items]
Common stock, shares authorized	250,000,000		250,000,000
Par value common shares (in USD per share)	$ 0.01		$ 0.01
Common stock, shares outstanding	41,172,173		41,172,173
PUCO merger equity ratio approval (at least)	50.00%
PUCO Equity Ratio	39.00%
PUCO merger, maximum long-term debt allowed	$ 750,000,000
PUCO merger, maximum long-term debt as percent of rate base (percent)	75.00%
Long-term Debt, Gross	$ 597,200,000
Proceeds from Contributions from Parent	80,000,000	0
Payments of Ordinary Dividends, Common Stock	$ 23,800,000	$ 9,000,000

Contractual Obligations, Comm61

Contractual Obligations, Commercial Commitments and Contingencies (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Public Utility, Property, Plant and Equipment [Line Items]
Due to third parties, current	$ 1.4	$ 0.9
THE DAYTON POWER AND LIGHT COMPANY [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Debt maturity, earliest	2,019
Debt maturity, latest	2,040
DPLE [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Third party guarantees	$ 36.7
Debt Obligation on 4.9% Equity Ownership [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Equity ownership interest	4.90%
Equity ownership interest aggregate cost	$ 70.1
Electric Generation Company [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Debt obligation	$ 1,430.6

Business Segments (Narrative) (

Business Segments (Narrative) (Details) - THE DAYTON POWER AND LIGHT COMPANY [Member]	3 Months Ended
	Mar. 31, 2018mi²customersegment
Segment Reporting Information [Line Items]
Number of Operating Segments | segment	2
Approximate number of retail customers | customer	523,000
Service area, square miles | mi²	6,000

Business Segments (Segment Fina

Business Segments (Segment Financial Information) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Segment Reporting Information [Line Items]
Gain (Loss) on Disposition of Business	$ (13.6)	$ 0
External customer revenues	293.2	323.9
Intersegment revenues	0	0
Total revenues	293.2	323.9
Depreciation and amortization	20.1	28
Fuel Costs	33.8	54.1
Depreciation and amortization	20.1	28
Impairment of Long-Lived Assets Held-for-use	0	66.4
Interest expense	28	27.3
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	20.5	(83.2)
Net income/ (loss)	16.9	(51.7)
Capital expenditures	27.3	41.4
Total assets	1,895.3		$ 2,049.2
Operating Segments [Member] | Transmission and Distribution [Member]
Segment Reporting Information [Line Items]
External customer revenues	195.8	189.8
Intersegment revenues	0.2	0.3
Total revenues	196	190.1
Depreciation and amortization	18.6	18.1
Impairment of Long-Lived Assets Held-for-use	0	0
Interest expense	8.2	7.6
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	19.3	25
Capital expenditures	24.6	26.3
Total assets	1,666.9		1,689.4
Operating Segments [Member] | Generation [Member]
Segment Reporting Information [Line Items]
Gain (Loss) on Disposition of Business	52.5
External customer revenues	95	131.8
Intersegment revenues	0	0
Total revenues	95	131.8
Depreciation and amortization	1.5	7
Impairment of Long-Lived Assets Held-for-use	0	66.3
Interest expense	0	0
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	71	(86.8)
Capital expenditures	1.7	14.1
Total assets	228.9		275
Corporate, Non-Segment [Member]
Segment Reporting Information [Line Items]
Gain (Loss) on Disposition of Business	54.4
External customer revenues	2.4	2.3
Intersegment revenues	0.6	1.4
Total revenues	3	3.7
Depreciation and amortization	0	2.9
Impairment of Long-Lived Assets Held-for-use	0	0.1
Interest expense	19.8	19.8
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	(69.8)	(21.4)
Capital expenditures	1	1
Total assets	580.4		468
Adjustments and Eliminations [Member]
Segment Reporting Information [Line Items]
External customer revenues	0	0
Intersegment revenues	(0.8)	(1.7)
Total revenues	(0.8)	(1.7)
Depreciation and amortization	0	0
Impairment of Long-Lived Assets Held-for-use	0	0
Interest expense	0	(0.1)
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	0	0
Capital expenditures	0	0
Total assets	(580.9)		(383.2)
Subsidiaries [Member]
Segment Reporting Information [Line Items]
Gain (Loss) on Disposition of Business	(12.4)	0
Depreciation and amortization	18.6	18.1
Fuel Costs	0.9	0
Depreciation and amortization	18.6	23.5
Impairment of Long-Lived Assets Held-for-use	0	66.3
Interest expense	8.2	7.6
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	19.3	25
Net income / (loss) from continuing operations	15.7	17
Discontinued operations, net of tax	0	(58.8)
Net income/ (loss)	15.7	(41.8)
Total assets	1,666.9		$ 1,689.4
Subsidiaries [Member] | Generation [Member]
Segment Reporting Information [Line Items]
Discontinued operations, net of tax		(58.8)
Other Operating Income (Expense) [Member]
Segment Reporting Information [Line Items]
Gain (Loss) on Disposition of Business	13.6	0
AES Ohio Generation peakers [Member]
Segment Reporting Information [Line Items]
Gain (Loss) on Disposition of Business	1.9
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	$ 7.2	$ 0.3

Revenue (Details)

Revenue (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Revenue from Contract with Customer, Excluding Assessed Tax	$ 290.3
Derivatives Accounts Receivable, Gross	1.7
RTO Revenue	12.9
RTO Capacity Revenue	29.2
Revenues	293.2
Contract with Customer, Asset, Gross	73	$ 79.4
Transmission and Distribution [Member]
RTO Revenue	11.1
RTO Capacity Revenue	1.9
Revenues	196
Generation [Member]
RTO Revenue	1.8
RTO Capacity Revenue	27.3
Revenues	95
Corporate, Non-Segment [Member]
RTO Revenue	0
RTO Capacity Revenue	0
Revenues	3
Adjustments and Eliminations [Member]
RTO Revenue	0
RTO Capacity Revenue	0
Revenues	(0.8)
Subsidiaries [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	186.8
Alternative Revenue Programs Accounts Receivable, Gross	3.1
RTO Revenue	11.1
RTO Capacity Revenue	1.9
Revenues	196
Contract with Customer, Asset, Gross	58.8	$ 62.1
Other Revenues [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	2.4
Other non-606 revenue	0
Other Revenues [Member] | Transmission and Distribution [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	0
Other non-606 revenue	0
Other Revenues [Member] | Generation [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	2.4
Other non-606 revenue	0.6
Other Revenues [Member] | Adjustments and Eliminations [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	0
Other non-606 revenue	(0.6)
Wholesale Revenue [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	84.8
Derivative Revenue	(6.3)
Wholesale Revenue [Member] | Transmission and Distribution [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	12.6
Derivative Revenue	0
Wholesale Revenue [Member] | Generation [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	72.2
Derivative Revenue	(6.3)
Wholesale Revenue [Member] | Corporate, Non-Segment [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	0
Derivative Revenue	0
Wholesale Revenue [Member] | Adjustments and Eliminations [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	0
Derivative Revenue	0
Wholesale Revenue [Member] | Subsidiaries [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	12.6
Retail Revenue [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	161
Other non-606 revenue	9.2
Retail Revenue [Member] | Transmission and Distribution [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	161.2
Other non-606 revenue	9.2
Retail Revenue [Member] | Generation [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	0
Other non-606 revenue	0
Retail Revenue [Member] | Corporate, Non-Segment [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	0
Other non-606 revenue	0
Retail Revenue [Member] | Adjustments and Eliminations [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	(0.2)
Other non-606 revenue	0
Retail Revenue [Member] | Subsidiaries [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	161.2
Other non-606 revenue	$ 9.2

Dispositions (Details)

Dispositions (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (Loss) on Disposition of Business	$ (13.6)	$ 0
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	20.5	(83.2)
Property, Plant and Equipment, Additions	27.3	41.4
Impairment of Long-Lived Assets Held-for-use	0	66.4
AES Ohio Generation peakers [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of Other Productive Assets	239.3
Gain (Loss) on Disposition of Business	1.9
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	7.2	0.3
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
Subsidiaries [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (Loss) on Disposition of Business	(12.4)	0
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	19.3	25
Impairment of Long-Lived Assets Held-for-use	0	$ 66.3
Subsidiaries [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 Fixed-as

Fixed-asset Impairment Fixed-asset Impairment (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Impairment of Long-Lived Assets Held-for-use	$ 0	$ 66.4
Stuart [Member]
Impairment of Long-Lived Assets Held-for-use		39.1
Impaired Assets to be Disposed of by Method Other than Sale, Amount of Impairment Loss		9.8
Killen [Member]
Impairment of Long-Lived Assets Held-for-use		27.3
Impaired Assets to be Disposed of by Method Other than Sale, Amount of Impairment Loss		6.4
THE DAYTON POWER AND LIGHT COMPANY [Member]
Impairment of Long-Lived Assets Held-for-use	$ 0	66.3
Level 3 [Member] | Stuart [Member]
Property, Plant, and Equipment, Fair Value Disclosure		3.3
Level 3 [Member] | Killen [Member]
Property, Plant, and Equipment, Fair Value Disclosure		$ 7.9

Generation Separation (Details)

Generation Separation (Details) - Subsidiaries [Member] - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 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
Loss from discontinued operations	$ 0	(88.7)
Discontinued Operation, Tax Effect of Discontinued Operation	0	(29.9)
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent	0	$ (58.8)
Debt Percentage of Rate Base		75.00%
Long-term Debt, Gross	$ 597.2
Transmission and Distribution [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long-term Debt, Gross		$ 750
Generation [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operation, Interest Expense		0.2
Cash Provided by (Used in) Operating Activities, Discontinued Operations		(11.8)
Cash Provided by (Used in) Investing Activities, Discontinued Operations		12.9
Cash Provided by (Used in) Financing Activities, Discontinued Operations		(1.1)
Disposal Group, Including Discontinued Operation, Revenue		121
Disposal Group, Including Discontinued Operation, Costs of Goods Sold		(69.8)
Disposal Group, Including Discontinued Operation, Operating and Other Expenses		(73.6)
Disposal Group, Including Discontinued Operation, Fixed-Asset Impairment		(66.3)
Loss from discontinued operations		(88.7)
Discontinued Operation, Tax Effect of Discontinued Operation		(29.9)
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent		$ (58.8)

Held for Sale (Details)

Held for Sale (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	$ 20.5	$ (83.2)
Subsidiaries [Member]
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	$ 19.3	$ 25