10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(x) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2018

OR

( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ____________ to ____________

Commission File Number	Registrant, State of Incorporation, Address and Telephone Number	I.R.S. Employer Identification No.
1-9052	DPL INC.	31-1163136
	(An Ohio Corporation)
	1065 Woodman Drive Dayton, Ohio 45432
	937-259-7215
1-2385	THE DAYTON POWER AND LIGHT COMPANY	31-0258470
	(An Ohio Corporation)
	1065 Woodman Drive Dayton, Ohio 45432
	937-259-7215

Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

DPL Inc.	Yes o	No x
The Dayton Power and Light Company	Yes o	No x

Each of DPL Inc. and The Dayton Power and Light Company is a voluntary filer that has filed all applicable reports under Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months.

Indicate by check mark whether each registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

DPL Inc.	Yes x	No o
The Dayton Power and Light Company	Yes x	No o

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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act.

	Large accelerated filer	Accelerated filer	Non- accelerated filer (Do not check if a smaller reporting company)	Smaller reporting company	Emerging growth company
DPL Inc.	o	o	x	o	o
The Dayton Power and Light Company	o	o	x	o	o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

DPL Inc.	o
The Dayton Power and Light Company	o

Indicate by check mark whether each registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

DPL Inc.	Yes o	No x
The Dayton Power and Light Company	Yes o	No x

All of the outstanding common stock of DPL Inc. is indirectly owned by The AES Corporation. All of the outstanding common stock of The Dayton Power and Light Company is owned by DPL Inc.

As of May 8, 2018, each registrant had the following shares of common stock outstanding:

Registrant	Description	Shares Outstanding
DPL Inc.	Common Stock, no par value	1
The Dayton Power and Light Company	Common Stock, $0.01 par value	41,172,173

This combined Form 10-Q is separately filed by DPL Inc. and The Dayton Power and Light Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to a registrant other than itself.

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DPL Inc. and The Dayton Power and Light Company

Table of Contents

Quarterly Report on Form 10-Q

Quarter Ended March 31, 2018

		Page No.
Glossary of Terms		5
Forward-Looking Statements		7
Part I Financial Information
Item 1	Financial Statements – DPL Inc. and The Dayton Power and Light Company (Unaudited)
	DPL Inc.
	Condensed Consolidated Statements of Operations	10
	Condensed Consolidated Statements of Comprehensive Income / (Loss)	11
	Condensed Consolidated Balance Sheets	12
	Condensed Consolidated Statements of Cash Flows	13
	Notes to Condensed Consolidated Financial Statements	14
	The Dayton Power and Light Company
	Condensed Statements of Operations	41
	Condensed Statements of Comprehensive Income / (Loss)	42
	Condensed Balance Sheets	43
	Condensed Statements of Cash Flows	44
	Notes to Condensed Financial Statements	45
Item 2	Management’s Discussion and Analysis of Financial Condition and Operations	64
	Electric Sales and Customers	85
Item 3	Quantitative and Qualitative Disclosures about Market Risk	85
Item 4	Controls and Procedures	85

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DPL Inc. and The Dayton Power and Light Company

Table of Contents (cont.)

Quarterly Report on Form 10-Q

Quarter Ended March 31, 2018

		Page No.
Part II Other Information
Item 1	Legal Proceedings	86
Item 1A	Risk Factors	86
Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	86
Item 3	Defaults Upon Senior Securities	86
Item 4	Mine Safety Disclosures	86
Item 5	Other Information	86
Item 6	Exhibits	87
Other
	Signatures	88

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GLOSSARY OF TERMS 

The following terms are used in this Form 10-Q:

Term	Definition
2017 ESP	DP&L's ESP, approved October 20, 2017, effective November 1, 2017
AES	The AES Corporation, a global power company and the ultimate parent company of DPL
AES Ohio Generation	AES Ohio Generation, LLC, a wholly-owned subsidiary of DPL that owns and operates generation facilities from which it makes wholesale sales
AOCI	Accumulated Other Comprehensive Income
ARO	Asset Retirement Obligation
ASU	Accounting Standards Update
CAA	U.S. Clean Air Act
Capacity Market	The purpose of the capacity market is to enable PJM to obtain sufficient resources to reliably meet the needs of electric customers within the PJM footprint. PJM procures capacity, through a multi-auction structure, on behalf of the load serving entities to satisfy the load obligations. There are four auctions held for each Delivery Year (running from June 1 through May 31). The Base Residual Auction is held three years in advance of the Delivery Year and there is one Incremental Auction held in each of the subsequent three years. AES Ohio Generation’s capacity is located in the “rest of” RTO area of PJM.
CCR	Coal combustion residuals
CP	In 2015, PJM adopted changes to the capacity market known as “Capacity Performance”. The CP program offers the potential for higher capacity revenues, combined with substantially increased penalties for non-performance or under-performance during certain periods identified as “capacity performance hours.” The AES Ohio Generation units operate under the CP construct effective June 1, 2016.
CPP	Clean Power Plan
CRES	Competitive Retail Electric Service
D.C. Circuit Court	United States Court of Appeals for the District of Columbia Circuit
DMR	Distribution Modernization Rider
DPL	DPL Inc.
DPLER	DPL Energy Resources, Inc., formerly a wholly-owned subsidiary of DPL which sold competitive electric energy and other energy services. DPLER was sold by DPL on January 1, 2016. The DPLER sale agreement was signed on December 28, 2015.
DP&L	The Dayton Power and Light Company, the principal subsidiary of DPL and a public utility that delivers electricity to residential, commercial, industrial and governmental customers in a 6,000-square mile area of West Central Ohio
Dths	Decatherms, unit of heat energy equal to 10 therms. One therm is equal to 100,000 British Thermal Units
EBITDA	Earnings before interest, taxes, depreciation and amortization. EBITDA also excludes the Fixed-asset impairment
EGU	Electric Generating Unit
ERISA	The Employee Retirement Income Security Act of 1974
ESP	The Electric Security Plan is a plan that a utility must file with the PUCO to establish SSO rates pursuant to Ohio law
FASB	Financial Accounting Standards Board
FASC	FASB Accounting Standards Codification
FERC	Federal Energy Regulatory Commission
FGD	Flue Gas Desulfurization
Form 10-K	DPL’s and DP&L’s combined Annual Report on Form 10-K for the fiscal year ended December 31, 2017, which was filed on February 26, 2018
First and Refunding Mortgage	DP&L’s First and Refunding Mortgage, dated October 1, 1935, as amended, with the Bank of New York Mellon as Trustee

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GLOSSARY OF TERMS (cont.)
Term	Definition
FTR	Financial Transmission Right
GAAP	Generally Accepted Accounting Principles in the United States of America
Generation Separation	The transfer on October 1, 2017 to AES Ohio Generation of the DP&L-owned generating facilities and related liabilities pursuant to an asset contribution agreement with a subsidiary that was then merged into AES Ohio Generation
GHG	Greenhouse Gas
kV	Kilovolt, 1,000 volts
kWh	Kilowatt-hours
LIBOR	London Inter-Bank Offering Rate
Master Trust	DP&L established a Master Trust to hold assets that could be used for the benefit of employees participating in employee benefit plans
Merger	The merger of DPL and Dolphin Sub, Inc., a wholly-owned subsidiary of AES. On November 28, 2011, DPL became a wholly-owned subsidiary of AES.
Miami Valley Lighting	Miami Valley Lighting, LLC is a wholly-owned subsidiary of DPL established in 1985 to provide street and outdoor lighting services to customers in the Dayton region. The Company serves businesses, communities and neighborhoods in West Central Ohio with over 70,000 lighting solutions for more than 190 businesses and 180 local governments.
MRO	Market Rate Option, a market-based plan that a utility may file with PUCO to establish SSO rates pursuant to Ohio law
MTM	Mark to Market
MVIC	Miami Valley Insurance Company, a wholly-owned insurance subsidiary of DPL that provides insurance services to DPL and its subsidiaries and, in some cases, insurance services to partner companies related to jointly-owned facilities operated by DP&L
MW	Megawatt
MWh	Megawatt-hour
NAV	Net asset value
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Corporation
Non-bypassable	Charges that are assessed to all customers regardless of whom the customer selects as their retail electric generation supplier
NOV	Notice of Violation
NOx	Nitrogen Oxide
NPDES	National Pollutant Discharge Elimination System
NSPS	New Source Performance Standards
NYMEX	New York Mercantile Exchange
Ohio EPA	Ohio Environmental Protection Agency
OTC	Over-The-Counter
OVEC	Ohio Valley Electric Corporation, an electric generating company in which DP&L holds a 4.9% equity interest
Peaker assets	The generation and related assets for the 586.0 MW Tait combustion turbine and diesel generation facility, the 236.0 MW Montpelier combustion turbine generation facility, the 101.5 MW Yankee combustion turbine generation and solar facility, the 25.0 MW Hutchings combustion turbine generation facility, the 12.0 MW Monument diesel generation facility, and the 12.0 MW Sidney diesel generation facility that were sold on March 27, 2018
PJM	PJM Interconnection, LLC, an RTO
PUCO	Public Utilities Commission of Ohio

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GLOSSARY OF TERMS (cont.)
Term	Definition
RPM	Reliability Pricing Model. The Reliability Pricing Model was PJM’s capacity construct prior to the implementation of the CP program.
RTO	Regional Transmission Organization
SCR	Selective Catalytic Reduction
SEC	Securities and Exchange Commission
SEET	Significantly excessive earnings test
SERP	Supplemental Executive Retirement Plan
Service Company	AES US Services, LLC, the shared services affiliate providing accounting, finance, and other support services to AES’ U.S. and Utilities SBU businesses
SO2	Sulfur Dioxide
SSO	Standard Service Offer represents the regulated rates, authorized by the PUCO, charged to DP&L retail customers that take retail generation service from DP&L within DP&L’s service territory
T&D	DP&L’s electric transmission and distribution businesses, which distribute electricity to residential, commercial, industrial and governmental customers
USD	U.S. dollar
USEPA	U.S. Environmental Protection Agency
USF	The Universal Service Fund is a statewide program which provides qualified low-income customers in Ohio with income-based bills and energy efficiency education programs
U.S. and Utilities SBU	U. S. and Utilities Strategic Business Unit, AES’ reporting unit covering the businesses in the United States, including DPL

FORWARD-LOOKING STATEMENTS

Certain statements contained in this report are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Matters discussed in this report that relate to events or developments that are expected to occur in the future, including management’s expectations, strategic objectives, business prospects, anticipated economic performance and financial condition and other similar matters constitute forward-looking statements. Forward-looking statements are based on management’s beliefs, assumptions and expectations of future economic performance, taking into account the information currently available to management. These statements are not statements of historical fact and are typically identified by terms and phrases such as “anticipate,” “believe,” “intend,” “estimate,” “expect,” “continue,” “should,” “could,” “may,” “plan,” “project,” “predict,” “will” and similar expressions. Such forward-looking statements are subject to risks and uncertainties and investors are cautioned that outcomes and results may vary materially from those projected due to various factors beyond our control, including but not limited to:

• growth in our service territory and changes in demand and demographic patterns;

• impacts of weather on retail sales and wholesale prices;

• impacts of renewable energy generation, natural gas prices and other market factors on wholesale prices;

• weather-related damage to our electrical system;

• fuel, commodity and other input costs;

• performance of our suppliers;

• transmission and distribution system reliability and capacity;

• purchased power costs and availability;

• regulatory action, including, but not limited to, the review of our basic rates and charges by the PUCO;

• federal and state legislation and regulations;

• changes in our credit ratings or the credit ratings of AES;

• fluctuations in the value of pension plan assets, fluctuations in pension plan expenses and our ability to fund defined benefit pension plans;

▪ changes in financial or regulatory accounting policies;

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▪ environmental matters, including costs of compliance with current and future environmental laws and requirements;

▪ interest rates, inflation rates and other costs of capital;

▪ the availability of capital;

▪ the ability of subsidiaries to pay dividends or distributions to DPL;

▪ level of creditworthiness of counterparties to contracts and transactions;

▪ labor strikes or other workforce factors, including the ability to attract and retain key personnel;

▪ facility or equipment maintenance, repairs and capital expenditures;

▪ significant delays or unanticipated cost increases associated with large construction projects;

▪ the availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material;

▪ local economic conditions;

▪ catastrophic events such as fires, explosions, cyber-attacks, terrorist acts, acts of war, pandemic events, or natural disasters such as floods, earthquakes, tornadoes, severe winds, ice or snow storms, droughts, or other similar occurrences;

▪ costs and effects of legal and administrative proceedings, audits, settlements, investigations and claims and the ultimate disposition of litigation;

▪ industry restructuring, deregulation and competition;

▪ issues related to our participation in PJM, including the cost associated with membership, allocation of costs, costs associated with transmission expansion, the recovery of costs incurred, and the risk of default of other PJM participants;

▪ changes in tax laws and the effects of our strategies to reduce tax payments;

▪ the use of derivative contracts;

▪ product development, technology changes, and changes in prices of products and technologies; and

▪ the risks and other factors discussed in this report and other DPL and DP&L filings with the SEC.

Forward-looking statements speak only as of the date of the document in which they are made. We disclaim any obligation or undertaking to provide any updates or revisions to any forward-looking statement to reflect any change in our expectations or any change in events, conditions or circumstances on which the forward-looking statement is based. If we do update one or more forward-looking statements, no inference should be made that we will make additional updates with respect to those or other forward-looking statements.

All such factors are difficult to predict, contain uncertainties that may materially affect actual results, and many are beyond our control. See Item 1A - Risk Factors in our Annual Report on Form 10-K for the fiscal year ended December 31, 2017 and the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section in such report and this Quarterly Report on Form 10-Q for a more detailed discussion of the foregoing and certain other factors that could cause actual results to differ materially from those reflected in such forward-looking statements and that should be considered in evaluating our outlook.

You may read and copy any document we file at the SEC’s public reference room located at 100 F Street N.E., Washington, D.C. 20549, USA. Please call the SEC at (800) SEC-0330 for further information on the public reference room. Our SEC filings are also available to the public from the SEC’s website at www.sec.gov.

COMPANY WEBSITES

DPL’s public internet site is www.dplinc.com. DP&L’s public internet site is www.dpandl.com. The information on these websites is not incorporated by reference into this report.

Part I – Financial Information

This report includes the combined filing of DPL and DP&L. Throughout this report, the terms “we,” “us,” “our” and “ours” are used to refer to both DPL and DP&L, respectively and altogether, unless the context indicates otherwise. Discussions or areas of this report that apply only to DPL or DP&L will be clearly noted in the applicable section.

Item 1 – Financial Statements

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FINANCIAL STATEMENTS

DPL INC.

9

DPL INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
	Three months ended
	March 31,
$ in millions	2018			2017
Revenues	$	293.2		$	323.9
Cost of revenues:
Net fuel cost	33.8			54.1
Net purchased power cost	97.8			102.0
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			28.0
General taxes	22.4			24.2
Fixed-asset impairment	—			66.4
Other, net (Note 2):	14.9			18.2
Total operating expenses	112.5			219.5
Operating income / (loss)	49.1			(51.7		)
Other income / (expense), net
Investment loss	(0.1		)	—
Interest expense	(28.0		)	(27.3		)
Charge for early redemption of debt	(0.7		)	—
Other income / (expense), net	0.2			(4.2		)
Total other expense, net	(28.6		)	(31.5		)
Income / (loss) before income tax	20.5			(83.2		)
Income tax expense / (benefit)	3.6			(31.5		)
Net income / (loss)	$	16.9		$	(51.7	)

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

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DPL INC.
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME / (LOSS)
	Three months ended March 31,
$ in millions	2018			2017
Net income / (loss)	$	16.9		$	(51.7	)
Equity securities activity:
Change in fair value of equity securities, net of income tax expense of $0.0 for each respective period	—			0.2
Reclassification to earnings, net of income tax expense of $0.0 for each respective period	—			(0.1		)
Reclassification to Retained earnings, net of income tax benefit of $0.6 and $0.0 for each respective period	(1.0		)	—
Total change in fair value of equity securities	(1.0		)	0.1
Derivative activity:
Change in derivative fair value, net of income tax expense of $(0.1) and $(2.8) for each respective period	0.9			5.2
Reclassification to earnings, net of income tax (expense) / benefit of $0.8 and $(0.5) for each respective period	2.3			1.0
Total change in fair value of derivatives	3.2			6.2
Pension and postretirement activity:
Prior service cost for the period, net of income tax benefit of $0.0 and $0.2 for each respective period	—			(0.3		)
Net loss for period, net of income tax benefit of $0.0 and $0.7 for each respective period	—			(1.2		)
Reclassification to earnings, net of income tax expense of $(0.1) and $(0.5) for each respective period	0.1			0.8
Total pension and postretirement adjustments	0.1			(0.7		)
Other comprehensive income	2.3			5.6
Net comprehensive income / (loss)	$	19.2		$	(46.1	)

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

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DPL INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
$ in millions	March 31, 2018			December 31, 2017
ASSETS
Current assets:
Cash and cash equivalents	$	123.9		$	24.5
Restricted cash	27.4			1.9
Accounts receivable, net (Note 2)	101.2			98.7
Inventories (Note 2)	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 - current	—			250.3
Total current assets	372.5			525.5
Property, plant & equipment:
Property, plant & equipment	1,589.0			1,554.7
Less: Accumulated depreciation and amortization	(291.8		)	(278.6		)
	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
LIABILITIES AND SHAREHOLDER'S DEFICIT
Current liabilities:
Current portion of long-term debt (Note 7)	$	105.6		$	4.7
Short-term debt	20.0			10.0
Accounts payable	71.5			70.1
Accrued taxes	84.5			80.0
Accrued interest	34.1			16.4
Customer security deposits	22.4			21.8
Regulatory liabilities, current	8.5			14.8
Insurance and claims costs	3.0			3.0
Other current liabilities	25.9			42.8
Liabilities held for sale - current	—			13.2
Total current liabilities	375.5			276.8
Non-current liabilities:
Long-term debt (Note 7)	1,471.0			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			101.0
Asset retirement obligations	128.3			131.2
Other deferred credits	14.1			14.3
Total non-current liabilities	2,039.3			2,356.7
Commitments and contingencies (Note 11)
Common shareholder's deficit
Common stock:
1,500 shares authorized; 1 share issued and outstanding at March 31, 2018 and December 31, 2017	—			—
Other paid-in capital	2,375.0			2,330.4
Accumulated other comprehensive income	3.1			0.8
Accumulated deficit	(2,897.6		)	(2,915.5		)
Total common shareholder's deficit	(519.5		)	(584.3		)
Total liabilities and shareholder's deficit	$	1,895.3		$	2,049.2

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

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DPL INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
	Three months ended March 31,
$ in millions	2018			2017
Cash flows from operating activities:
Net income / (loss)	$	16.9		$	(51.7	)
Adjustments to reconcile net income / (loss) to net cash from operating activities:
Depreciation and amortization	20.1			28.0
Charge for early redemption of debt	0.7			—
Deferred income taxes	(41.7		)	(4.7		)
Fixed-asset impairment	—			66.4
Loss on disposal and sale of business	13.6			—
Loss on asset disposal, net	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			(66.0		)
Accrued interest payable	17.6			15.9
Security deposits	0.6			17.6
Insurance claims costs	—			1.2
Pension, retiree and other 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 disposal and sale of business	234.9			—
Payments on disposal and sale of business	(14.5		)	—
Insurance proceeds	2.8			1.2
Other investing activities, net	(0.5		)	0.2
Net cash provided by / (used in) investing activities	195.4			(40.0		)
Cash flows from financing activities:
Retirement of long-term debt	(131.1		)	(7.4		)
Borrowings from revolving credit facilities	25.0			—
Repayment of borrowings from revolving credit facilities	(15.0		)	—
Net cash used in financing activities	(121.1		)	(7.4		)
Cash, cash equivalents, and restricted cash:
Net change	124.9			(20.9		)
Balance at beginning of period	26.4			83.6
Cash, cash equivalents, and restricted cash at end of period	$	151.3		$	62.7
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	7.0		$	10.4
Non-cash financing and investing activities:
Accruals for capital expenditures	$	8.9		$	10.7
Non-cash proceeds from sale of business	$	4.1		$	—
Non-cash capital contribution (Note 10):	$	45.1		$	—

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

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DPL Inc.

Notes to Condensed Consolidated Financial Statements (Unaudited)

Note 1 – 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 a6,000-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

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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.

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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. Transition method: Retrospective for presentation of non-service cost expense. Prospective for the change in 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. Transition method: retrospective.	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.

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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. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2017-12, Derivatives and Hedging (Topic 815): Targeted improvements to Accounting for Hedging Activities	The standard updates the hedge accounting model to expand the ability to hedge nonfinancial and financial risk components, reduce complexity, and ease certain documentation and assessment requirements. When facts and circumstances are the same as at the previous quantitative test, a subsequent quantitative effectiveness test is not required. The standard also eliminates the requirement to separately measure and report hedge ineffectiveness. For cash flow hedges, this means that the entire change in the fair value of a hedging instrument will be recorded in other comprehensive income and amounts deferred will be reclassified to earnings in the same income statement line as the hedged item. Transition method: modified retrospective with the cumulative effect adjustment recorded to the opening balance of retained earnings as of the initial application date. Prospective for presentation and disclosures.	January 1, 2019. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
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. Transition method: modified retrospective.	January 1, 2019. Early adoption is permitted.	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. Transition method: various.	January 1, 2020. Early adoption is permitted only as of January 1, 2019.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2016-02, 2018-01, Leases (Topic 842)	See "2016-02, Leases (Topic 842)" below.	January 1, 2019. Early adoption is permitted.	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

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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.

Note 2 – 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

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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 endedMarch 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

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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

Note 3 – 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.

Note 4 – 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.

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DPL's undivided ownership interest in such facilities at March 31, 2018, was as follows:

	DPL Share		DPL Carrying Value
	Ownership (%)	Summer Production Capacity (MW)	Gross Plant In Service ($ in millions)		Accumulated Depreciation ($ in millions)		Construction Work in Process ($ in millions)
Jointly-owned production units
Conesville - Unit 4	16.5	129	$	0.6	$	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.

Note 5 – 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.

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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.

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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

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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.

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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 (through remaining life)	10.0	%
				Weighted-average cost of capital	7.0	%
Killen	$	7.9	Discounted cash flow	Pre-tax operating margin (through remaining life)	22.0	%
				Weighted-average cost of capital	7.0	%

Note 6 – 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

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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 (in thousands)		Sales (in thousands)		Net Purchases/ (Sales) (in thousands)
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 (in thousands)		Sales (in thousands)			Net Purchases/ (Sales) (in thousands)
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.

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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.

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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.

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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

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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.

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Note 7 – 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 endedMarch 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 DPL6.75% 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,

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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 than2.50 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 TotalConsolidated 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.

Note 8 – 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%

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Income tax expense for the three months endedMarch 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.

Note 9 – 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.

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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

Note 10 – 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.

Note 11 – 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

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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 SO₂, 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.

Note 12 – 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

35

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.

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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

Note 13 – 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

37

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.

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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.

Note 14 – 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 assetswas $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.

Note 15 – 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.

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FINANCIAL STATEMENTS

The Dayton Power and Light Company

40

THE DAYTON POWER AND LIGHT COMPANY
CONDENSED STATEMENTS OF OPERATIONS
	Three months ended
	March 31,
$ in millions	2018			2017
Revenues	$	196.0		$	190.1
Cost of revenues:
Net fuel cost	0.9			—
Net purchased power cost	83.8			81.1
Total cost of revenues	84.7			81.1
Gross margin	111.3			109.0
Operating expenses:
Operation and maintenance	32.2			38.0
Depreciation and amortization	18.6			18.1
General taxes	19.3			18.9
Loss on disposal of business (Note 14)	12.4			—
Total operating expenses	82.5			75.0
Operating income	28.8			34.0
Other expense, net
Investment loss	(0.1		)	—
Interest expense	(8.2		)	(7.6		)
Charge for early redemption of debt	(0.5		)	—
Other expense, net	(0.7		)	(1.4		)
Total other expense, net	(9.5		)	(9.0		)
Income from continuing operations before income tax	19.3			25.0
Income tax expense from continuing operations	3.6			8.0
Net income from continuing operations	15.7			17.0
Discontinued operations (Note 13)
Loss from discontinued operations	—			(88.7		)
Income tax benefit for discontinued operations	—			(29.9		)
Net loss from discontinued operations	—			(58.8		)
Net income / (loss)	$	15.7		$	(41.8	)

See Notes to Condensed Financial Statements.

These interim statements are unaudited.

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THE DAYTON POWER AND LIGHT COMPANY
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME / (LOSS)
	Three months ended March 31,
$ in millions	2018			2017
Net income / (loss)	$	15.7		$	(41.8	)
Equity securities activity:
Change in fair value of equity securities, net of income tax expense of $0.0 for each respective period	—			0.2
Reclassification to earnings, net of income tax benefit of $0.0 for each respective period	—			(0.1		)
Reclassification to Retained earnings, net of income tax benefit of $0.6 and $0.0 for each respective period	(1.1		)	—
Total change in fair value of equity securities	(1.1		)	0.1
Derivative activity:
Change in derivative fair value, net of income tax expense of $(0.1) and $(2.8) for each respective period	0.5			5.2
Reclassification to earnings, net of income tax (expense) / benefit of $0.5 and $(0.5) for each respective period	(0.3		)	1.0
Total change in fair value of derivatives	0.2			6.2
Pension and postretirement activity:
Prior service costs for the period, net of income tax benefit of $0.0 and $0.6 for each respective period	—			(1.1		)
Net loss for period, net of income tax benefit of $0.0 and $0.3 for each respective period	—			(0.5		)
Reclassification to earnings, net of income tax expense of $(0.2) and $(1.3) for each respective period	0.9			2.5
Total pension and postretirement adjustments	0.9			0.9
Other comprehensive income	—			7.2
Net comprehensive income / (loss)	$	15.7		$	(34.6	)

See Notes to Condensed Financial Statements.

These interim statements are unaudited.

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THE DAYTON POWER AND LIGHT COMPANY
CONDENSED BALANCE SHEETS
$ in millions	March 31, 2018			December 31, 2017
ASSETS
Current assets:
Cash and cash equivalents	$	1.0		$	5.2
Restricted cash	0.9			0.4
Accounts receivable, net (Note 2)	73.0			70.8
Inventories (Note 2)	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		)
	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
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Current portion of long-term debt (Note 7)	$	4.6		$	4.6
Short-term debt (Note 7)	20.0			10.0
Accounts payable	50.0			46.6
Accrued taxes	69.4			70.1
Accrued interest	1.2			0.8
Customer 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 (Note 7)	583.1			642.0
Deferred taxes	134.3			131.0
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
Asset retirement obligations	4.7			8.0
Other deferred credits	6.8			7.1
Total non-current liabilities	1,076.2			1,177.1
Commitments and contingencies (Note 11)
Common shareholder's equity:
Common stock, at par value of $0.01 per share	0.4			0.4
250,000,000 shares authorized, 41,172,173 shares issued and outstanding
Other paid-in capital	741.7			685.8
Accumulated other comprehensive loss	(36.2		)	(36.2		)
Accumulated 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

See Notes to Condensed Financial Statements.

These interim statements are unaudited.

43

THE DAYTON POWER AND LIGHT COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
	Three months ended March 31,
$ in millions	2018			2017
Cash flows from operating activities:
Net income / (loss)	$	15.7		$	(41.8	)
Adjustments to reconcile net income / (loss) to net cash from operating activities:
Depreciation and amortization	18.6			23.5
Charge for early redemption of debt	0.5			—
Deferred income taxes	3.6			0.4
Fixed-asset impairment	—			66.3
Loss on disposal of business	12.4			—
Loss on asset disposal, net	—			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
Pension, retiree and other 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 on disposal of business	(14.5		)	—
Other investing activities, net	(0.3		)	0.1
Net cash used in investing activities	(39.4		)	(34.0		)
Cash flows from financing activities:
Returns of capital paid to parent	(23.8		)	(9.0		)
Borrowings from revolving credit facilities	25.0			—
Repayment of borrowings from revolving credit facilities	(15.0		)	—
Capital contributions from parent	80.0			—
Retirement of long-term debt	(61.1		)	(1.1		)
Issuance of short-term debt - related party	—			30.0
Repayment of short-term debt - related party	—			(35.0		)
Net cash provided by / (used in) financing activities	5.1			(15.1		)
Cash, cash equivalents, and restricted cash:
Net change	(3.7		)	(17.3		)
Balance at beginning of period	5.6			30.6
Cash, cash equivalents, and restricted cash at end of period	$	1.9		$	13.3
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

See Notes to Condensed Financial Statements.

These interim statements are unaudited.

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The Dayton Power and Light Company

Notes to Condensed Financial Statements (Unaudited)

Note 1 – Overview and Summary of Significant Accounting Policies

Description of Business

DP&Lis 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 a6,000square 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

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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. Transition method: Retrospective for presentation of non-service cost expense. Prospective for the change in 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.

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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. Transition method: retrospective.	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. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements.

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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. Transition method: modified retrospective with the cumulative effect adjustment recorded to the opening balance of retained earnings as of the initial application date. Prospective for presentation and disclosures.	January 1, 2019. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our 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. Transition method: modified retrospective.	January 1, 2019. Early adoption is permitted.	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. Transition method: various.	January 1, 2020. Early adoption is permitted only as of January 1, 2019.	We are currently evaluating the impact of adopting the standard on our financial statements.
2016-02, 2018-01, Leases (Topic 842)	See "2016-02, Leases (Topic 842)" below.	January 1, 2019. Early adoption is permitted.	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.

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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.

Note 2 – 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

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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	)

Note 3 – 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

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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.

Note 4 – 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.

Note 5 – 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.

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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.

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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

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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.

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Note 6 – 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.

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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.

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Note 7 – 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 TotalConsolidated 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

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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.

Note 8 – 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 endedMarch 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).

Note 9 – 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.

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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

Note 10 – 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.

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Note 11 – 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.

Note 12 – 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.

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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.

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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.

Note 13 – 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.

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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.

Note 14 – 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.

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Item 2 – Management's Discussion and Analysis of Financial Condition and Results of Operations

This report includes the combined filing of DPL and DP&L.On November 28, 2011, DPL became an indirectly wholly-owned subsidiary of AES, a global power company. Throughout this report, the terms “we,” “us,” “our” and “ours” are used to refer to both DPL and DP&L, respectively and together, unless the context indicates otherwise. Discussions or areas of this report that apply only to DPL or DP&L will clearly be noted in the section.

FORWARD-LOOKING INFORMATION

The following discussion contains forward-looking statements and should be read in conjunction with the accompanying Condensed Consolidated Financial Statements and related footnotes of DPL and the Condensed Financial Statements and related footnotes of DP&L included in Part I – Financial Information, the risk factors in Item 1A to Part I of our Form 10-K for the fiscal year ended December 31, 2017 and in Item 1A to Part II of this Quarterly Report on Form 10-Q, and our “Forward-Looking Statements” section of this Form 10-Q. For a list of certain abbreviations or acronyms in this discussion, see the Glossary at the beginning of this Form 10-Q.

Overview of Our Business–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 a6,000square 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.

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.

Topics in Management's Discussion and Analysis

Our discussion covers the following:

• Review of Results of Operations

◦ DPL

▪ DPL - T&D Segment

▪ DPL - Generation Segment

◦ DP&L

• Key Trends and Uncertainties

• Capital Resources and Liquidity

• Market Risk

• Critical Accounting Estimates

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RESULTS OF OPERATIONS HIGHLIGHTS – DPL

DPL’s results of operations include the results of its subsidiaries, including its principal subsidiary DP&L. All material intercompany accounts and transactions have been eliminated in consolidation. A separate specific discussion of the results of operations for DP&L is presented elsewhere in this report.

	Three months ended
	March 31,
$ in millions	2018			2017
Revenues:
Retail	$	170.2		$	171.9
Wholesale	78.5			103.1
RTO revenues	12.9			14.0
RTO capacity revenues	29.2			32.1
Other revenues	2.4			2.8
Total revenues	293.2			323.9
Cost of revenues:
Fuel cost:
Fuel	33.8			54.4
Gains from the sale of coal	—			(0.3		)
Net fuel cost	33.8			54.1
Purchased power:
Purchased power	60.8			77.4
RTO charges	33.1			21.1
RTO capacity charges	3.9			3.2
Mark-to-market losses	—			0.3
Net purchased power cost	97.8			102.0
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			28.0
General taxes	22.4			24.2
Fixed-asset impairment	—			66.4
Other, net	14.9			18.2
Total operating expenses	112.5			219.5
Operating income / (loss)	49.1			(51.7		)
Other income / (expense), net:
Investment loss	(0.1		)	—
Interest expense	(28.0		)	(27.3		)
Charge for early redemption of debt	(0.7		)	—
Other income / (expense), net	0.2			(4.2		)
Total other expense, net	(28.6		)	(31.5		)
Income / (loss) from continuing operations before income tax (a)	$	20.5		$	(83.2	)

(a) For purposes of discussing operating results, we present and discuss Income / (loss) from continuing operations before income tax. This format is useful to investors because it allows analysis and comparability of operating trends and includes the same information that is used by management to make decisions regarding our financial performance.

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DPL – Revenues

Retail customers, especially residential and commercial customers, consume more electricity during warmer and colder weather than they do during mild temperatures. Therefore,our retail sales volume is impacted by the number of heating and cooling degree-days occurring during a year. Cooling degree-days typically have a more significant impact than heating degree-days since some residential customers do not use electricity to heat their homes.

	Three months ended March 31,
	2018	2017
Heating degree-days (a)	2,858	2,292
Cooling degree-days (a)	3	2

(a) Heating and cooling degree-days are a measure of the relative heating or cooling required for a home or business. The heating degrees in a day are calculated as the degrees that the average actual daily temperature is below 65 degrees Fahrenheit. For example, if the average temperature on March 20th was 40 degrees Fahrenheit, the heating degrees for that day would be the 25-degree difference between 65 degrees and 40 degrees. Similarly, cooling degrees in a day are calculated as the degrees that the average actual daily temperature is above 65 degrees Fahrenheit.

We sell generation into the wholesale market which covers a multi-state area and settles on an hourly basis throughout the year. Factors impacting our wholesale sales volume each hour of the year include: wholesale market prices; retail demand throughout the entire wholesale market area; availability of our generating plants and non-affiliated generating plants to sell into the wholesale market; contracted wholesale sales and our variable generation costs. Our goal is to make wholesale sales when it is profitable to do so.

The following table provides a summary of changes in revenues compared to the same period in the prior year:

	Three months ended
	March 31,
$ in millions	2018 vs. 2017
Retail
Rate	$	(6.0	)
Volume	7.9
Other miscellaneous	(3.6		)
Total retail change	(1.7		)
Wholesale
Rate	23.7
Volume	(48.3		)
Total wholesale change	(24.6		)
RTO revenues and RTO capacity revenues
RTO revenues and RTO capacity revenues	(4.0		)
Other
Other revenues	(0.4		)
Total revenues change	$	(30.7	)

During the three months ended March 31, 2018, Revenues decreased $30.7 million to $293.2 million from $323.9 million in the same period of the prior year. This decrease was primarily the result of the components of revenue discussed below:

• Retail revenues decreased $1.7 millionprimarily due to lower average DP&L retail rates and lower other miscellaneous revenues, partially offset by higher DP&L retail volumes. The decrease in average retail rates was primarily driven by decreased collections on the competitive bid and energy efficiency revenue rate riders. These decreases were partially offset by the implementation of the DMR in November of 2017. The increase in retail volume was primarily driven by favorable weather in 2018, as heating degree-days

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increased by 566 degree-days. The impacts discussed above resulted in a favorable $7.9 million retail volume variance and an unfavorable $6.0 million retail price variance. In addition to the unfavorable retail price variance, there was an unfavorable other miscellaneous variance of $3.6 million primarily due to energy efficiency shared savings recorded in 2017.

• Wholesale revenues decreased $24.6 million primarily as a result of an unfavorable $48.3 million wholesale volume variance and a favorable $23.7 million wholesale price variance. The decrease in wholesale volumes of $48.3 million was primarily driven by a 52% decrease in internal generation at DPL's plants in 2018, mostly due to the sale of the Miami Fort and Zimmer stations in December of 2017. The favorable price variance of $23.7 million was primarily driven by increases in PJM market prices in 2018, partially offset by higher derivative losses in 2018.

• RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and PJM capacity payments, decreased $4.0 million compared to the same period in the prior year. This decrease was the result of a $1.1 million decrease in RTO revenues due to lower rates and availability related to compensation for DPL's reactive supply and operating reserves and a $2.9 million decrease in revenue realized from the PJM capacity auction in 2018 due to the decrease in generating capacity from the sale of the Miami Fort and Zimmer stations in December of 2017. This decrease in generating capacity was partially offset by higher average prices in the CP auction in 2018. The capacity price that became effective in June of 2017 was $152/MW-day, compared to $59/MW-day under the base RPM auction and $134/MW-day for the transitional CP auction in June of 2016.

DPL – Cost of Revenues

During the three months ended March 31, 2018, Cost of revenues decreased $24.5 million compared to the same period in the prior year:

• Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $20.3 million compared to the same period in the prior year primarily driven by a 52% decrease in internal generation, due to the sale of the Miami Fort and Zimmer stations in December of 2017, partially offset by a 28% increase in average fuel cost per MWh.

• Net purchased power decreased $4.2 million compared to the same period in the prior year. This decrease was driven by the following factors:

◦ Purchased power decreased $16.6 million primarily due to a $20.3 million price decrease, partially offset by a $3.7 million volume increase compared to the same period in the prior year. The price decrease was primarily driven by lower rates in the competitive bid process in 2018 than 2017 and derivative gains in 2018 as opposed to derivative losses in 2017, while the volume increase was primarily driven by the increase in DP&L retail demand in 2018.

◦ RTO charges increased $12.0 million compared to the same period in the prior year primarily due to higher transmission and congestion charges driven by higher market prices. RTO charges are incurred by DP&L as a member of PJM and primarily include transmission charges within our network, which are incurred and charged to customers in the transmission rider, transmission and congestion losses incurred on DP&L's wholesale revenues, and costs associated with load obligations for retail customers.

◦ RTO capacity charges increased $0.7 million compared to the same period in the prior year.

◦ Mark-to-market losses decreased $0.3 million due to changes in power prices in 2018 and 2017.

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DPL – Operation and Maintenance

During the three months ended March 31, 2018, Operation and Maintenance expense decreased $27.6 million compared to the same period in the prior year. The main drivers of this change are as follows:

	Three months ended
	March 31,
$ in millions	2018 vs. 2017
Decrease in generating facilities operating and maintenance expenses, primarily due to the sale of the Miami Fort and Zimmer stations	$	(16.2	)
Decrease in alternative energy and energy efficiency programs (a)	(10.0		)
Increase in maintenance of overhead transmission and distribution lines	1.1
Other, net	(2.5		)
Net change in operation and maintenance expense	$	(27.6	)

(a) There is a corresponding offset in Revenues associated with these programs.

DPL – Depreciation and Amortization

During the three months ended March 31, 2018, Depreciation and amortization decreased $7.9 million compared to the same period in the prior year. The decrease was primarily a result of the fixed-asset impairments in the first and fourth quarters of 2017, which reduced depreciation expense due to the lower asset values. In addition, the decrease was attributable to the discontinuation of Miami Fort station, Zimmer station, and the Peaker assets' depreciation expense, due to the sale of these facilities.

DPL – General Taxes

During the three months ended March 31, 2018, General taxes decreased $1.8 million compared to the same period in the prior year. The decrease was primarily the result of lower property tax expense for 2018 compared to 2017.

DPL – Fixed-asset Impairment

During the three months ended March 31, 2017, DPL recorded an impairment of fixed assets of $66.4 million. DPL recognized asset impairment expense of $39.1 million and $27.3 million for Stuart station and Killen station, respectively. For more information, see Note 15 – Fixed-asset Impairments of Notes to DPL's Condensed Consolidated Financial Statements.

DPL – Operating Expenses - Other

During the three months ended March 31, 2018, DPL recorded other operating expenses of $14.9 million primarily due to the loss on the transfer of business interests in the Beckjord facility of $11.7 million and the loss on the sale of the Peaker assets of $1.9 million. In addition, there were other miscellaneous operating expenses of $1.3 million.

During the three months ended March 31, 2017, DPL recorded other operating expenses of $18.2 million primarily due to the $16.2 million write-off of plant materials and supplies inventory at the Stuart and Killen stations and the $3.2 million net loss recorded on the disposal of assets related to the high-pressure feedwater heater shell failure on Unit 1 at Stuart station. These losses were partially offset by $1.2 million of insurance proceeds.

DPL – Other Income / (Expense), net

Other expense, net of $4.2 million during the three months ended March 31, 2017 changed to Other income, net of $0.2 million during the three months ended March 31, 2018. The net change of $4.4 million was primarily due to the pension curtailment charges recorded in 2017 associated with the announced plant closures.

DPL – Income Tax Expense / (Benefit)

Income tax benefit of $31.5 million during the three months ended March 31, 2017 changed to Income tax expense of $3.6 million during the three months ended March 31, 2018. The net change of $35.1 million was primarily due to a pre-tax loss in the prior year versus pre-tax income in the current year, partially offset by the change in the federal income tax rate from 35% to 21%, due to the TCJA.

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RESULTS OF OPERATIONS BY SEGMENT - DPL

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 and profits are eliminated in consolidation. Certain shared and corporate costs are allocated among reporting segments.

See Note 12 – Business Segments of Notes to DPL’s Condensed Consolidated Financial Statements for additional information regarding DPL’s reportable segments.

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The following table presents DPL’s Income / (loss) from continuing operations before income tax by business segment:

	Three months ended
	March 31,
$ in millions	2018			2017
T&D	$	19.3		$	25.0
Generation	71.0			(86.8		)
Other	(69.8		)	(21.4		)
Income / (loss) from continuing operations before income tax (a)	$	20.5		$	(83.2	)

(a) For purposes of discussing operating results, we present and discuss Income / (loss) from continuing operations before income tax. This format is useful to investors because it allows analysis and comparability of operating trends and includes the same information that is used by management to make decisions regarding our financial performance.

RESULTS OF OPERATIONS HIGHLIGHTS – DPL – T&D Segment

The results of operations of the T&D segment for DPL are identical in all material respects and for all periods presented to those of DP&L,which are included in Part I - Item 2 - Management's Discussion and Analysis of Financial Condition and Results of Operations (RESULTS OF OPERATIONS HIGHLIGHTS – DP&L) of this Form 10-Q.

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RESULTS OF OPERATIONS HIGHLIGHTS – DPL – Generation Segment

	Three months ended
	March 31,
$ in millions	2018			2017
Revenues:
Wholesale	$	65.9		$	98.5
RTO revenues	1.8			2.5
RTO capacity revenues	27.3			30.8
Total revenues	95.0			131.8
Cost of revenues:
Fuel cost:
Fuel	32.9			54.4
Losses from the sale of coal	—			(0.3		)
Net fuel cost	32.9			54.1
Purchased power:
Purchased power	(5.1		)	10.7
RTO charges	16.1			6.7
RTO capacity charges	2.6			3.2
Mark-to-market losses	—			0.3
Net purchased power cost	13.6			20.9
Total cost of revenues	46.5			75.0
Gross margin	48.5			56.8
Operating expenses:
Operation and maintenance	24.0			41.6
Depreciation and amortization	1.5			7.0
General taxes	3.1			5.2
Fixed-asset impairment	—			66.3
Other, net	(51.1		)	18.2
Total operating expenses / (credits), net	(22.5		)	138.3
Operating income / (loss)	71.0			(81.5		)
Other expense, net
Total other expense, net	—			(5.3		)
Income / (loss) from continuing operations before income tax (a)	$	71.0		$	(86.8	)

(a) For purposes of discussing operating results, we present and discuss Income / (loss) from continuing operations before income tax. This format is useful to investors because it allows analysis and comparability of operating trends and includes the same information that is used by management to make decisions regarding our financial performance.

DPL –Generation Segment – Revenues

During the three months ended March 31, 2018, the segment’s revenues decreased $36.8 million to $95.0 million from $131.8 million in the same period of the prior year. This decrease was primarily the result of lower wholesale volumes and lower RTO capacity and other revenues, partially offset by higher average wholesale rates.

• Wholesale revenues decreased $32.6 million primarily as a result of an unfavorable wholesale volume variance of $38.5 million, partially offset by a favorable wholesale price variance of $5.9 million. The decrease in wholesale volumes was primarily driven by a 52% decrease in internal generation at DPL's plants in 2018, mostly due to the sale of the Miami Fort and Zimmer stations in December of 2017. The favorable price variance was primarily driven by increases in PJM market prices in 2018, partially offset by higher derivative losses in 2018.

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• RTO capacity and other revenues, consisting primarily of PJM capacity revenues, regulation services, reactive supply and operating reserves, decreased $4.2 million compared to the same period in the prior year primarily due to a $0.7 million decrease in RTO revenues due to lower rates and availability related to compensation for DPL's reactive supply and operating reserves and a $3.5 million decrease in revenue realized from the PJM capacity auction in 2018 due to the decrease in generating capacity from the sale of the Miami Fort and Zimmer stations in December of 2017. This decrease in generating capacity was partially offset by higher average prices in the CP auction in 2018. The capacity price that became effective in June of 2017 was $152/MW-day, compared to $59/MW-day under the base RPM auction and $134/MW-day for the transitional CP auction in June of 2016.

DPL –Generation Segment – Cost of Revenues

During the three months ended March 31, 2018, Total cost of revenues decreased $28.5 million compared to the prior year. This decrease was a result of:

• Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $21.2 million compared to the same period in the prior year primarily driven by a 52% decrease in internal generation, due to the sale of the Miami Fort and Zimmer stations in December of 2017, partially offset by a 28% increase in average fuel cost per MWh.

• Net purchased power decreased $7.3 million compared to the prior year. This decrease was driven by the following factors:

◦ Purchased power decreased $15.8 million primarily driven by derivative gains in 2018 as opposed to derivative losses in 2017.

◦ RTO charges increased $9.4 million compared to the same period in the prior year primarily due to higher transmission and congestion charges.

◦ RTO capacity charges decreased $0.6 million compared to the same period in the prior year.

◦ Mark-to-market losses decreased $0.3 million due to changes in power prices in 2018 and 2017.

DPL –Generation Segment – Operation and Maintenance

During the three ended March 31, 2018, Operation and Maintenance expense decreased $17.6 million compared to the same period in the prior year. The main drivers of this change are as follows:

	Three months ended
	March 31,
$ in millions	2018 vs. 2017
Decrease in generating facilities operating and maintenance expenses, primarily due to the sale of the Miami Fort and Zimmer stations	$	(16.3	)
Other, net	(1.3		)
Net change in operating expenses	$	(17.6	)

DPL –Generation Segment – Depreciation and Amortization

During the three months ended March 31, 2018, Depreciation and amortization decreased $5.5 million compared to the same period in the prior year. The decrease was primarily a result of the fixed-asset impairments in the first and fourth quarters of 2017, which reduced depreciation expense due to the lower asset values. In addition, the decrease was attributable to the discontinuation of the Miami Fort station, Zimmer station, and the Peaker assets' depreciation expense, as these facilities were sold or held for sale for the entire quarter.

DPL –Generation Segment – Fixed-asset Impairment

During the three months ended March 31, 2017, the Generation segment recorded fixed-asset impairments, without the effect of the purchase accounting adjustments included in the Other column of segments, of $66.3 million. In the first quarter of 2017, the Board of Directors of DP&L approved the retirement of the then 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. The co-owners of these facilities agreed with DP&L to proceed with this plan of retirement. DPL performed a long-lived asset impairment analysis

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and determined that the carrying amounts of the Facilities were not recoverable. As a result, DPL's Generation segment recognized asset impairment expense of $66.3 million in the first quarter of 2017.

DPL–Generation Segment – Operating Expenses - Other, Net

During the three months ended March 31, 2018, the Generation segment recorded other operating income of $51.1 million, primarily due to the Generation segment's gain on the sale of the Peaker assets of $52.5 million. This gain on the sale was offset by a loss of $54.4 million included within the Other segment due to the asset values established by applying purchase accounting, resulting in a consolidated DPL loss on the sale of the Peaker assets of $1.9 million. Within the Generation segment, the gain on the sale of the Peaker assets was partially offset by other miscellaneous operating expenses of $1.4 million.

During the three months ended March 31, 2017, the Generation segment recorded other operating expenses of $18.2 million primarily due to the $16.2 million write-off of plant materials and supplies inventory at the Stuart and Killen stations and the $3.2 million net loss recorded on the disposal of assets related to the high-pressure feedwater heater shell failure on Unit 1 at Stuart station. These losses were partially offset by $1.2 million of insurance proceeds.

DPL–Generation Segment – Other Income / (Expense), net

During the three months ended March 31, 2017, the Generation segment recorded Other expense, net, of $5.3 million primarily due to the pension curtailment charges recorded in 2017 associated with the announced plant closures.

RESULTS OF OPERATIONS HIGHLIGHTS – DP&L

	Three months ended
	March 31,
$ in millions	2018			2017
Revenues:
Retail	$	170.4		$	172.2
Wholesale	12.6			5.1
RTO revenues	11.1			11.5
RTO capacity revenues	1.9			1.3
Total revenues	196.0			190.1
Cost of revenues:
Net fuel cost	0.9			—
Purchased power:
Purchased power	65.5			66.7
RTO charges	17.0			14.4
RTO capacity charges	1.3			—
Net purchased power cost	83.8			81.1
Total cost of revenues	84.7			81.1
Gross margin	111.3			109.0
Operating expenses:
Operation and maintenance	32.2			38.0
Depreciation and amortization	18.6			18.1
General taxes	19.3			18.9
Loss on disposal of business (Note 14)	12.4			—
Total operating expenses	82.5			75.0
Operating income	28.8			34.0
Other expense, net
Investment loss	(0.1		)	—
Interest expense	(8.2		)	(7.6		)
Charge for early redemption of debt	(0.5		)	—
Other expense, net	(0.7		)	(1.4		)
Total other expense, net	(9.5		)	(9.0		)
Income from operations before income tax (a)	$	19.3		$	25.0

(a) For purposes of discussing operating results, we present and discuss Income from operations before income tax. This format is useful to investors because it allows analysis and comparability of operating trends and includes the same information used by management to make decisions regarding our financial performance.

DP&L – Revenues

Retail customers, especially residential and commercial customers, consume more electricity during warmer and colder weather than they do during mild temperatures. Therefore,our retail sales volume is impacted by the number of heating and cooling degree-days occurring during a year. Cooling degree-days typically have a more significant impact than heating degree-days since some residential customers do not use electricity to heat their homes.

We sell generation into the wholesale market which covers a multi-state area and settles on an hourly basis throughout the year. Factors impacting our wholesale sales volume each hour of the year include: wholesale market prices; retail demand throughout the entire wholesale market area; availability of our generating plants and non-affiliated generating plants to sell into the wholesale market; contracted wholesale sales and our variable generation costs. Our goal is to make wholesale sales when it is profitable to do so.

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The following table provides a summary of changes in revenues compared to the same period in the prior year:

	Three months ended
	March 31,
$ in millions	2018 vs. 2017
Retail
Rate	$	(6.0	)
Volume	7.8
Other miscellaneous	(3.6		)
Total retail change	(1.8		)
Wholesale
Wholesale revenues	7.5
RTO revenues and RTO capacity revenues
RTO revenues and RTO capacity revenues	0.2
Total revenues change	$	5.9

During the three months ended March 31, 2018, Revenues increased $5.9 million to $196.0 million from $190.1 million in the same period in the prior year. This increase was primarily the result of the components of revenue discussed below:

• Retail revenues decreased $1.8 millionprimarily due to lower average DP&L retail rates and lower other miscellaneous revenues, partially offset by higher DP&L retail volumes. The decrease in average retail rates was primarily driven by decreased collections on the competitive bid and energy efficiency revenue rate riders. These decreases were partially offset by the implementation of the DMR in November of 2017. The increase in retail volume was primarily driven by favorable weather in 2018, as heating degree-days increased by 566 degree-days. The impacts discussed above resulted in a favorable $7.8 million retail volume variance and an unfavorable $6.0 million retail price variance. In addition to the unfavorable retail price variance, there was an unfavorable other miscellaneous variance of $3.6 million primarily due to energy shared savings recorded in 2017.

• Wholesale revenues increased $7.5 millioncompared to the same period in the prior year. These revenues consist of DP&L's 4.9% share of the generation output of OVEC, which is sold into PJM at market prices.

• RTO capacity and other revenues increased $0.2 million compared to the same period in the prior year.

DP&L – Cost of Revenues

During the three months ended March 31, 2018, Cost of revenues increased $3.6 million compared to the same period in the prior year:

• Net fuel costs, which represent expense recognition coinciding with the collection of fuel costs through the regulatory fuel deferral, increased $0.9 million compared to the same period in the prior year.

• Net purchased power increased $2.7 million compared to the same period in the prior year. This increase was driven by the following factors:

◦ Purchased power decreased $1.2 million primarily due to a $10.3 million price decrease, partially offset by a $9.1 million volume increase compared to the same period in the prior year. The price decrease was primarily driven by lower rates in the competitive bid process in 2018 compared to the same period in 2017, while the volume increase was primarily driven by the increase in DP&L retail demand in 2018.

◦ RTO charges increased $2.6 million compared to the same period in the prior year primarily due to higher transmission and congestion charges. RTO charges are incurred by DP&L as a member of

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PJM and primarily include transmission charges within our network, which are incurred and charged to customers in the transmission rider, transmission and congestion losses incurred on DP&L's wholesale revenues, and costs associated with load obligations for retail customers.

◦ RTO capacity charges increased $1.3 million compared to the same period in the prior year primarily due to higher average CP auction prices in 2018.

DP&L – Operation and Maintenance

During the three months ended March 31, 2018, Operation and Maintenance expense decreased $5.8 million compared to the same period in the prior year. The main drivers of this change are as follows:

	Three months ended
	March 31,
$ in millions	2018 vs. 2017
Decrease in alternative energy and energy efficiency programs (a)	$	(10.0	)
Increase in group insurance expense associated with participation in the AES self-insurance plan	1.2
Increase in maintenance of overhead transmission and distribution lines	1.1
Other, net	1.9
Net change in operation and maintenance expense	$	(5.8	)

(a) There is a corresponding offset in Revenues associated with these programs.

DP&L – Depreciation and Amortization

During the three months ended March 31, 2018, Depreciation and amortization increased $0.5 million, compared to the same period in the prior year. The increase was primarily due to additional investments in transmission and distribution fixed assets.

DP&L – General Taxes

During the three months ended March 31, 2018, General taxes increased $0.4 million compared to the same period in the prior year. 

DP&L – Loss on Disposal of Business

During the three months ended March 31, 2018, DP&L recorded a Loss on disposal of business of $12.4 million due to the loss on the transfer of business interests in the Beckjord facility.

DP&L – Income Tax Expense

During the three months ended March 31, 2018, Income tax expense decreased $4.4 million compared to the same period in the prior year primarily due to lower pre-tax income in the current year versus the prior year and the change in the federal income tax rate from 35% to 21%, due to the TCJA.

DP&L - Discontinued Operations

During the three months ended March 31, 2017, DP&L recorded a loss from discontinued operations (net of tax) of $58.8 million. This loss relates to the discontinued DP&L Generation segment, which was transferred to AES Ohio Generation through Generation Separation on October 1, 2017. See Note 13 - Generation Separation in Notes to DP&L's Consolidated Financial Statements.

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KEY TRENDS AND UNCERTAINTIES

During the remainder of 2018 and beyond, we expect that our financial results will be driven primarily by retail demand, weather and, to a lesser extent, wholesale and capacity prices. In addition, DPL's and DP&L's financial results are likely to be driven by other factors including, but not limited to:

• the passage of new legislation, implementation of regulations or other changes in regulation;

• outcome of DP&L's pending distribution rate case;

• timely recovery of distribution capital expenditures through rate base growth;

• exiting generation assets now owned by AES Ohio Generation; and

• DPL's ability to reduce its cost structure.

Operational

In addition to our plans to exit coal generating capacity, we closed on a sale of our Peaker assets in March 2018.

For additional information on DPL's coal fired facilities see Note 4 – Property, Plant and Equipment of Notes to DPL's Condensed Consolidated Financial Statements.

Regulatory Environment

DPL’s, DP&L’s and our other subsidiaries’ facilities and operations are subject to a wide range of regulations and laws by federal, state and local authorities. As well as 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 these facilities and operations in an effort to comply, or to determine compliance, with such regulations. We record liabilities for losses that are probable and can be reasonably estimated. In addition to matters discussed or updated herein, our 2017 Form 10-K previously filed with the SEC during 2018 describes other regulatory matters which have not materially changed since that filing.

Ohio Competition and Regulatory Proceedings

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.

AES Ohio Generation filed an application before the FERC, which was accepted, to reduce its reactive power rates effective March 27, 2018, to reflect the sale of its peaking facilities.

In connection with any sale or closure of our generation plants, DPL and DP&L expect to incur certain cash and non-cash charges, some or all of which could be material to the business and financial condition of DPL and DP&L.

The Department of Energy (DOE) issued a Notice of Proposed Rule Making on September 29, 2017, which directed the FERC to exercise its authority to set just and reasonable rates that recognize the “resiliency” value provided by generation plants with certain characteristics, including having 90-days or more of on-site fuel and operating in markets where they do not receive rate base treatment through state ratemaking. On January 8, 2018, the FERC terminated this proceeding and established a new one soliciting comments from the RTOs regarding resiliency. RTO responses were submitted on March 9, 2018, but the timing and outcome of this proceeding, including effects on wholesale energy markets, remain uncertain.

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PJM Pricing - Capacity Auction Price

The PJM capacity base residual auction for the 2020/21 period cleared at a per megawatt price of $77/MW-day for our RTO area. The per megawatt prices for the periods 2019/20, 2018/19, 2017/18 and 2016/17 were $100/MW-day, $165/MW-day, $152/MW-day and $134/MW-day, respectively, based on previous auctions.

Environmental Matters

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 and operations 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 as of March 31, 2018. We have a number of environmental matters for which we have not accrued loss contingencies because the risk of loss is not probable or cannot be reasonably estimated. Of these, those that we believe are most likely to have a material effect are disclosed in our 2017 10-K. We evaluate the potential liability related to environmental matters quarterly and may revise our accruals. 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 EGUs and stations. Some of these matters could have material adverse effects on the operation of such EGUs and stations or our financial condition.

As a result of DPL’s decision to retire its Stuart and Killen generating stations, the following environmental regulations and requirements are not expected to have a material impact on DPL with respect to either of the two generating stations:

• water intake regulations finalized by the USEPA on May 19, 2014;

• the appeal of the NPDES permit governing the discharge of water from the Stuart station; and

• revised technology-based regulations governing water discharges from steam electric generating facilities, finalized by the USEPA on November 3, 2015.

We refer to the discussion in “Item 1. Business - Environmental Matters” in our 2017 Form 10-K for a discussion of certain recent developments in environmental laws and regulations.

The USEPA's final CCR rule became effective on October 19, 2015. Generally, the rule regulates CCR as nonhazardous solid waste and establishes national minimum criteria for existing and new CCR landfills and existing and new CCR surface impoundments (ash ponds), including location restrictions, design and operating criteria, groundwater monitoring, corrective action and closure requirements and post-closure care. On September 13, 2017, the USEPA indicated that it would reconsider certain provisions of the CCR rule in response to two petitions it received to reconsider the final rule. On March 15, 2018, the USEPA published a proposed amendment to the CCR rule. The USEPA stated that this proposal is the first of two amendments of the CCR rule, the second to be released later in 2018. The CCR rule, current or proposed amendments to the CCR rule, the results of groundwater monitoring data or the outcome of CCR-related litigation may have a material impact on our business, financial condition or results of operations.

CAPITAL RESOURCES AND LIQUIDITY

DPL and DP&L had cash and cash equivalents of $123.9 million and $1.0 million, respectively, at March 31, 2018. At that date, neither DPL nor DP&L had short-term investments. DPL and DP&L had aggregate principal amounts of long-term debt outstanding of $1,592.8 million and $597.2 million, respectively.

Approximately $105.6 million of DPL's long-term debt including $4.6 million of DP&L's long-term debt matures within the next twelve months, which we expect to repay using a combination of cash on hand, net cash provided by operating activities and/or net proceeds from the issuance of new debt. From time to time, we may elect to repurchase our outstanding debt through cash purchases, privately negotiated transactions or otherwise when management believes such repurchases are favorable to make. The amounts involved in any such repurchases may be material.

We depend on timely and continued access to capital markets to manage our liquidity needs. The inability to raise capital on favorable terms, to refinance existing indebtedness or to fund operations and other commitments during times of political or economic uncertainty could have material adverse effects on our financial condition and results

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of operations. In addition, changes in the timing of tariff increases or delays in regulatory determinations could affect the cash flows and results of operations of our businesses.

Our discussion of DPL’s financial condition, liquidity and capital requirements include the results of its principal subsidiary DP&L. All material intercompany accounts and transactions have been eliminated in consolidation.

CASH FLOWS – DPL

DPL’s financial condition, liquidity and capital requirements include the consolidated results of its principal subsidiary DP&L. All material intercompany accounts and transactions have been eliminated in consolidation. The following table summarizes the cash flows of DPL:

DPL	Three months ended March 31,
$ in millions	2018			2017
Net cash provided by operating activities	$	50.6		$	26.5
Net cash provided by / (used in) investing activities	195.4			(40.0		)
Net cash used in financing activities	(121.1		)	(7.4		)
Net change	124.9			(20.9		)
Balance at beginning of period	26.4			83.6
Cash, cash equivalents, and restricted cash at end of period	$	151.3		$	62.7

DPL– Change in cash flows from operating activities

	Three months ended March 31,						$ change
$ in millions	2018			2017			2018 vs. 2017
Net income / (loss)	$	16.9		$	(51.7	)	$	68.6
Depreciation and amortization	20.1			28.0			(7.9		)
Impairment expenses	—			66.4			(66.4		)
Deferred income taxes	(41.7		)	(4.7		)	(37.0		)
Other adjustments to Net income / (loss)	14.9			19.4			(4.5		)
Net income / (loss), adjusted for non-cash items	10.2			57.4			(47.2		)
Net change in operating assets and liabilities	40.4			(30.9		)	71.3
Net cash provided by operating activities	$	50.6		$	26.5		$	24.1

The net change in operating assets and liabilities during the three months ended March 31, 2018 compared to the three months ended March 31, 2017 was driven by the following:

$ in millions	$ Change
Increase from accrued taxes payable is primarily due to a prior year income tax benefit	$	74.7
Other	(3.4		)
Net increase in cash from changes in operating assets and liabilities	$	71.3

DPL– Cash flows from investing activities

Net cash from investing activities was $195.4 million for the three months endedMarch 31, 2018 compared to $(40.0) million for the three months endedMarch 31, 2017. Investing activity for the three months endedMarch 31, 2018 primarily relates to proceeds from the sale of business of $239.4 million, primarily due to the sale of the Peaker assets, partially offset by capital expenditures of $27.3 million and payment on the disposal of Beckjord of $14.5 million. Investing activity for the three months endedMarch 31, 2017 was primarily driven by capital expenditures of $41.4 million.

DPL– Cash flows from financing activities

Net cash used in financing activities was $(121.1) million for thethree months endedMarch 31, 2018 compared to $(7.4) million from financing activities for the three months endedMarch 31, 2017. The three months endedMarch 31, 2018 financing activity relates mainly to $131.1 million of payments on long-term debt primarily relating to the repayment of the remaining balance on the DPL term loan of $70.0 million and from the $60.0 million repayment on the DP&L tax-exempt term loan. This was partially offset by net revolving credit facility borrowings of $10.0

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million. The three months endedMarch 31, 2017 financing activity relates primarily to various term loan repayments of $7.4 million.

CASH FLOWS – DP&L

The following table summarizes the cash flows of DP&L:

DP&L	Three months ended March 31,
$ in millions	2018			2017
Net cash provided by operating activities	$	30.6		$	31.8
Net cash used in investing activities	(39.4		)	(34.0		)
Net cash provided by / (used in) financing activities	5.1			(15.1		)
Net change	(3.7		)	(17.3		)
Balance at beginning of period	5.6			30.6
Cash, cash equivalents, and restricted cash at end of period	$	1.9		$	13.3

DP&L– Change in cash flows from operating activities

	Three months ended March 31,						$ change
$ in millions	2018			2017			2018 vs. 2017
Net income / (loss)	$	15.7		$	(41.8	)	$	57.5
Depreciation and amortization	18.6			23.5			(4.9		)
Impairment expenses	—			66.3			(66.3		)
Other adjustments to Net income / (loss)	16.5			19.8			(3.3		)
Net income / (loss), adjusted for non-cash items	50.8			67.8			(17.0		)
Net change in operating assets and liabilities	(20.2		)	(36.0		)	15.8
Net cash provided by operating activities	$	30.6		$	31.8		$	(1.2	)

The net change in operating assets and liabilities during the three months ended March 31, 2018 compared to the three months ended March 31, 2017 was driven by the following:

$ in millions	$ Change
Increase from accounts payable due to timing of payments	32.3
Increase from deferred regulatory costs, net, due to collections on regulatory assets and liabilities	21.7
Decrease from accounts receivable due to timing of collections	(30.7		)
Other	(7.5		)
Net increase in cash from changes in operating assets and liabilities	$	15.8

DP&L– Cash flows from investing activities

Net cash from investing activities was $(39.4) million for thethree months endedMarch 31, 2018 compared to $(34.0) million for the three months endedMarch 31, 2017. The three months endedMarch 31, 2018 investing activity relates mainly to capital expenditures of $24.6 million, and payment on the disposal of Beckjord of $14.5 million. The three months endedMarch 31, 2017 investing activity was primarily driven by capital expenditures of $34.1 million.

DP&L– Cash flows from financing activities

Net cash provided by / (used in) financing activities was $5.1 million for the three months endedMarch 31, 2018 compared to $(15.1) million from financing activities for the three months endedMarch 31, 2017. The three months endedMarch 31, 2018 financing activity relates mainly to $61.1 million of payments on long-term debt, primarily relating to a $60.0 million repayment on the DP&L tax-exempt term loan, and dividends paid on common stock to parent of $23.8 million, which was partially offset by a $80.0 million capital contribution from DPL, and net revolving credit facility borrowings of $10.0 million. Net cash using in financing activities for the three months endedMarch 31, 2017 primarily relates to a first quarter term loan repayment of $1.1 million, and net repayments of borrowings from related parties of $5.0 million.

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LIQUIDITY

We expect our existing sources of liquidity to remain sufficient to meet our anticipated operating needs. Our business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and carrying costs, potential margin requirements related to energy hedges and dividend payments. In 2018 and subsequent years, we expect to satisfy these requirements with a combination of cash from operations and funds from debt financing as internal liquidity needs and market conditions warrant. We also expect that the borrowing capacity under bank credit facilities will continue to be available to us to manage working capital requirements during these periods.

At March 31, 2018, DP&L and DPL have access to the following revolving credit facilities:

$ in millions	Type	Maturity	Commitment		Amounts available as of March 31, 2018
DP&L	Revolving	July 2020	$	175.0	$	153.9
DPL	Revolving	July 2020	205.0		188.9
			$	380.0	$	342.8

DP&L has an unsecured revolving credit agreement with a syndicated bank group with a borrowing limit of $175.0 million and a $50.0 million letter of credit sublimit, as well as a feature that provides DP&L the ability to increase the size of the facility by an additional $100.0 million. This facility expires in July 2020. At March 31, 2018, there was one letter of credit in the amount of $1.1 million outstanding under this facility, and $20.0 million borrowed on the facility, with the remaining $153.9 million available to DP&L. Fees associated with this letter of credit facility were not material during the three months ended March 31, 2018 or 2017.

DPL has a revolving credit facility of $205.0 million, with a $200.0 million letter of credit sublimit and a feature that provides DPL the ability to increase the size of the facility by an additional $95.0 million. This facility is secured by a pledge of common stock that DPL owns in DP&L, limited to the amount permitted to be pledged under certain Indentures dated October 3, 2011 and October 6, 2014 between DPL and Wells Fargo Bank, NA and U.S. Bank National Association, respectively, as Trustee. The facility expires in July 2020. The springing maturity feature of this facility has been satisfied since the DPL Term Loan was paid in full on March 27,2018 and $101.0 million of the DPL senior unsecured bonds due October 1, 2019 were redeemed on April 30, 2018. At March 31, 2018, there were seven letters of credit in the aggregate amount of $16.1 million outstanding and no borrowings, with the remaining $188.9 million available to DPL. Fees associated with this facility were not material during the three months endedMarch 31, 2018 or 2017.

Capital Requirements

Planned construction additions for 2018 relate primarily to new investments in and upgrades to DP&L’s transmission and distribution system and power plant equipment. Capital projects are subject to continuing review and are revised in light of changes in financial and economic conditions, load forecasts, legislative and regulatory developments and changing environmental requirements, among other factors.

DPL is projecting to spend an estimated $359.0 million in capital projects for the period 2018 through 2020, of which $338.0 million is projected to be spent by DP&L. DP&L is subject to the mandatory reliability standards of NERC and Reliability First Corporation (RFC), one of the eight NERC regions, of which DP&L is a member. DP&L anticipates spending approximately $33.0 million within the next five years to reinforce its 138 kV system to comply with NERC standards. Our ability to complete capital projects and the reliability of future service will be affected by our financial condition, the availability of internal funds and the reasonable cost of external funds. We expect to finance our construction additions with a combination of cash on hand, short-term financing, long-term debt and cash flows from operations.

Long-term debt covenants

The DPL revolving credit facility has a Total Debt to EBITDA covenant that will be calculated, at the end of each fiscal quarter, by dividing total debt at the end of the current quarter by consolidated EBITDA for the four prior fiscal quarters. The ratio in the agreement is not to exceed 7.25 to 1.00 for any fiscal quarter ending September 30, 2015 through December 31, 2018; it then steps down not to exceed 7.00 to 1.00 for any fiscal quarter ending January 01, 2019 through June 30, 2019; it then steps down not to exceed 6.75 to 1.00 for any fiscal quarter ending July 01, 2019 through December 31, 2019; and it then steps down not to exceed 6.50 to 1.00 for any fiscal quarter ending January 01, 2020 and afterward. As of March 31, 2018, the financial covenant was met with a ratio of 5.31 to 1.00.

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The DPL revolving credit facility also has an EBITDA to Interest Expense covenant that is calculated at the end of each fiscal quarter by dividing consolidated EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period. The ratio, per the agreement, is to be not less than 2.10 to 1.00 for any fiscal quarter ending September 30, 2015 through December 31, 2018; it then steps up to be not less than 2.25 to 1.00 for any fiscal quarter ending March 31, 2019 through July 31, 2020. As of March 31, 2018, this financial covenant was met with a ratio of 2.76 to 1.00.

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. DP&L's TotalConsolidated 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 DP&L revolving credit facility and Bond Purchase and Covenants Agreement also have an EBITDA to Interest Expense financial covenant that is calculated at the end of each fiscal quarter, by dividing EBITDA for the four prior fiscal quarters by the interest charges for the same period. Both prior to and after completion of the separation of DP&L’s generation assets from its transmission and distribution assets, DP&L’sEBITDA to Interest Expense cannot be less than 2.50 to 1.00. As of March 31, 2018, this covenant was met with a ratio of 7.31 to 1.00.

Debt and Credit Ratings

The following table presents, as of the filing of this report, the debt ratings and outlook for DPL and DP&L, along with the effective or affirmed date of each rating.

	DPL	DP&L	Outlook	Effective or Affirmed
Fitch Ratings	BBB-(a) / BB+(b)	BBB+ (c)	Positive	October 2017
Moody's Investors Service, Inc.	Ba2 (b)	Baa2 (c)	Positive	April 2018 / October 2017 (d)
Standard & Poor's Financial Services LLC	BBB- (b)	BBB+ (c)	Stable	March 2018

(a) Rating relates to DPL’s Senior secured debt.

(b) Rating relates to DPL's Senior unsecured debt.

(c) Rating relates to DP&L’s Senior secured debt.

(d) DPL's debt rating was upgraded in April 2018; DP&L's debt rating was affirmed in October 2017.

The following table presents, as of the filing of this report, the credit ratings (issuer/corporate rating) and outlook for DPL and DP&L, along with the effective or affirmed date of each rating.

	DPL	DP&L	Outlook	Effective or Affirmed
Fitch Ratings	BB	BBB-	Positive	October 2017
Moody's Investors Service, Inc.	Ba3	Baa3	Positive	October 2017
Standard & Poor's Financial Services LLC	BBB-	BBB-	Stable	March 2018

If the rating agencies were to reduce our debt or credit ratings, our borrowing costs may increase, our potential pool of investors and funding resources may be reduced, and we may be required to post additional collateral under selected contracts. These events may have an adverse effect on our results of operations, financial condition and cash flows. In addition, any such reduction in our debt or credit ratings may adversely affect the trading price of our outstanding debt securities.

Off-Balance Sheet Arrangements

For information on guarantees, commercial commitments, and contractual obligations, see Note 11 – Contractual Obligations, Commercial Commitments and Contingencies of Notes to DPL’s Condensed Consolidated Financial

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Statements and Note 11 – Contractual Obligations, Commercial Commitments and Contingencies of Notes to DP&L’s Condensed Financial Statements.

MARKET RISK

We are subject to certain market risks including, but not limited to, changes in commodity prices for electricity, coal, environmental emissions and gas, changes in capacity prices and fluctuations in interest rates. We use various market risk sensitive instruments, including derivative contracts, primarily to limit our exposure to fluctuations in commodity pricing. Our Risk Management Committee (RMC), comprised of members of senior management, is responsible for establishing risk management policies and the monitoring and reporting of risk exposures relating to our generation units. The RMC meets on a regular basis with the objective of identifying, assessing and quantifying material risk issues and developing strategies to manage these risks.

Commodity Pricing Risk

Commodity pricing risk exposure includes the impacts of weather, market demand, increased competition and other economic conditions. To manage the volatility relating to these exposures at our generation units, we use a variety of non-derivative and derivative instruments including forward contracts and futures contracts. These instruments are used principally for economic hedging purposes and none are held for trading purposes. Derivatives that fall within the scope of derivative accounting under GAAP must be recorded at their fair value and marked to market unless they qualify for cash flow hedge accounting. MTM gains and losses on derivative instruments that qualify for cash flow hedge accounting are deferred in AOCI until the forecasted transactions occur. We adjust the derivative instruments that do not qualify for cash flow hedging to fair value monthly through the Statement of Operations or, where applicable, we recognize a corresponding Regulatory asset for above-market costs or a Regulatory liability for below-market costs in accordance with regulatory accounting under GAAP.

The coal market has increasingly been influenced by both international and domestic supply and consumption, making the price of coal more volatile than in the past, and while we have substantially all of the total expected coal volume needed to meet our retail and firm wholesale sales requirements for 2018 under contract; sales requirements may change. The majority of the contracted coal is purchased at fixed prices. Some contracts provide for periodic adjustments. Fuel costs are affected by changes in volume and price and are driven by a number of variables including weather, the wholesale market price of power, certain provisions in coal contracts related to government-imposed costs, counterparty performance and credit, scheduled outages and generation plant mix.

Wholesale Revenues

DPL sells its generation into the wholesale market when we can identify opportunities with positive margins. As a result of DPL's plans to exit coal-fired generation, increases or decreases in the price per megawatt-hour of wholesale power will have a less significant impact on our results of operations, financial position or cash flows going forward.

Fuel and Purchased Power Costs

We have a significant portion of projected 2018 fuel needs under contract. Most of our contracted coal is purchased at fixed prices although some contracts provide for periodic pricing adjustments. We may purchase SO₂ allowances for 2018; however, the exact consumption of SO₂ allowances will depend on market prices for power, availability of our generation units and the actual sulfur content of the coal burned. We may purchase some NO_X allowances for 2018 depending on NO_X emissions. Fuel costs are affected by changes in volume and price and are driven by a number of variables including weather, reliability of coal deliveries, scheduled outages and electric generation station mix.

DP&L conducts competitive bid auctions to purchase power for SSO service, as DP&L's SSO is 100% sourced through the competitive bid. AES Ohio Generation sometimes purchases power to source retail load in other service territories and to meet contracted wholesale requirements when generating facilities are not available due to planned and unplanned outages or when market prices are below the marginal costs associated with our generating facilities.

As a result of DPL's plans to exit coal-fired generation, we do not expect that changes in the prices of fuel and purchased power would have a material impact on our results of operations, financial position or cash flows.

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Interest Rate Risk

Because of our normal investing and borrowing activities, our financial results are exposed to fluctuations in interest rates which we manage through our regular financing activities. We maintain both cash on deposit and investments in cash equivalents that may be affected by adverse interest rate fluctuations. DP&L has both fixed-rate and variable-rate long-term debt. The variable-rate debt is comprised of bank held tax-exempt bonds and a variable rate term loan B. The variable-rate bonds and term loan B bear interest based on an underlying interest rate index, typically LIBOR. Market indexes can be affected by market demand, supply, market interest rates and other economic conditions. See Note 7 – Long-term Debt of Notes to DPL’s Condensed Consolidated Financial Statements and Note 7 – Long-term Debt of Notes to DP&L’s Condensed Financial Statements.

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.

Principal Payments and Interest Rate Detail by Contractual Maturity Date

The principal value of DPL’s long-term debt was $1,592.8 million at March 31, 2018, consisting of DPL’s unsecured notes, along with DP&L’s first mortgage bonds, tax-exempt bonds and the Wright-Patterson Air Force Base note. All of DPL’s long-term debt was adjusted to fair value at the date of the Merger. The fair value of this long-term debt at March 31, 2018 was $1,661.4 million, based on current market prices or discounted cash flows using current rates for similar issues with similar terms and remaining maturities. The following table provides information about DPL’s long-term debt obligations that are sensitive to interest rate changes:

DPL
	Principal payments due												At March 31, 2018
	during the twelve months ending
	March 31,												Principal		Fair
$ in millions	2019		2020		2021		2022		2023		Thereafter		Amount		Value
Long-term debt
Variable-rate debt	$	4.5	$	4.5	$	144.5	$	4.5	$	421.4	$	—	$	579.4	$	579.4
Average interest rate (a)	3.7%		3.7%		2.6%		3.7%		3.7%		—%
Fixed-rate debt	$	101.1	$	99.1	$	0.2	$	780.2	$	0.2	$	32.6	1,013.4		1,082.0
Average interest rate	6.7%		6.7%		4.2%		7.2%		4.2%		6.1%
Total													$	1,592.8	$	1,661.4

(a) Based on rates in effect at March 31, 2018

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The principal value of DP&L’s long-term debt was $597.2 million at March 31, 2018, consisting of its first mortgage bonds, tax-exempt bonds and the Wright-Patterson Air Force Base note. The fair value of this long-term debt was $597.2 million, based on current market prices or discounted cash flows using current rates for similar issues with similar terms and remaining maturities. The following table provides information about DP&L’s debt obligations that are sensitive to interest rate changes. DP&L’s debt was not revalued as a result of the Merger.

DP&L
	Principal payments due												At March 31, 2018
	during the twelve months ending
	March 31,												Principal		Fair
$ in millions	2019		2020		2021		2022		2023		Thereafter		Amount		Value
Long-term debt
Variable-rate debt	$	4.5	$	4.5	$	144.5	$	4.5	$	421.4	$	—	$	579.4	$	579.4
Average interest rate (a)	3.7%		3.7%		2.6%		3.7%		3.7%		—%
Fixed-rate debt	$	0.1	$	0.1	$	0.2	$	0.2	$	0.2	$	17.0	17.8		17.8
Average interest rate	4.2%		4.2%		4.2%		4.2%		4.2%		4.2%
Total													$	597.2	$	597.2

(a) Based on rates in effect at March 31, 2018

Long-term debt maturities and repayments occurring in the next twelve months are discussed under "CAPITAL RESOURCES AND LIQUIDITY".

Long-term Debt Interest Rate Risk Sensitivity Analysis

Our estimate of market risk exposure is presented for our fixed-rate and variable-rate long-term debt at March 31, 2018 for which an immediate adverse market movement causes a potential material impact on our financial condition, results of operations or the fair value of the debt. We believe that the adverse market movement represents the hypothetical loss to future earnings and does not represent the maximum possible loss nor any expected actual loss, even under adverse conditions, because actual adverse fluctuations would likely differ. As of March 31, 2018, we did not hold any market risk sensitive instruments that were entered into for trading purposes.

The following tables present the carrying value and fair value of our long-term debt, along with the impact of a change of one percent in interest rates:

DPL	At March 31, 2018				One percent
	Principal		Fair		interest rate
$ in millions	Amount		Value		risk
Long-term debt
Variable-rate debt	$	579.4	$	579.4	$	5.8
Fixed-rate debt	1,013.4		1,082.0		10.1
Total	$	1,592.8	$	1,661.4	$	15.9

DP&L	At March 31, 2018				One percent
	Principal		Fair		interest rate
$ in millions	Amount		Value		risk
Long-term debt
Variable-rate debt	$	579.4	$	579.4	$	5.8
Fixed-rate debt	17.8		17.8		0.2
Total	$	597.2	$	597.2	$	6.0

DPL’s long-term debt is comprised of both fixed-rate debt and variable-rate debt. In regard to fixed-rate debt, the interest rate risk with respect to DPL’s long-term debt primarily relates to the potential impact a decrease of one percentage point in interest rates has on the fair value of DPL’s$1,082.0 million of fixed-rate debt and not on DPL’s financial condition or results of operations. On the variable-rate debt, the interest rate risk with respect to DPL’s long-term debt represents the potential impact an increase of one percentage point in the interest rate has on DPL’s results of operations related to DPL’s$579.4 million variable-rate long-term debt outstanding as of March 31, 2018.

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DP&L’s interest rate risk with respect to DP&L’s long-term debt primarily relates to the potential impact a decrease in interest rates of one percentage point has on the fair value of DP&L’s$17.8 million of fixed-rate debt and not on DP&L’s financial condition or DP&L’s results of operations. On the variable-rate debt, the interest rate risk with respect to DP&L’s long-term debt represents the potential impact of an increase of one percentage point in the interest rate has on DP&L’s results of operations related to DP&L’s$579.4 million variable-rate long-term debt outstanding as of March 31, 2018.

Credit Risk

Credit risk is the risk of an obligor's failure to meet the terms of any investment contract, loan agreement or otherwise perform as agreed. Credit risk arises from all activities in which success depends on issuer, borrower or counterparty performance, whether reflected on or off the balance sheet. We limit our credit risk by assessing the creditworthiness of potential counterparties before entering into transactions with them and continue to evaluate their creditworthiness after transactions have been originated. We use the three leading corporate credit rating agencies and other current market-based qualitative and quantitative data to assess the financial strength of our counterparties on an ongoing basis. We may require various forms of credit assurance from our counterparties to mitigate credit risk.

Critical Accounting Estimates

DPL’s Condensed Consolidated Financial Statements and DP&L’s Condensed Financial Statements are prepared in accordance with GAAP. In connection with the preparation of these financial statements, our management is required to make assumptions, estimates and judgments that affect the reported amounts of assets, liabilities, revenues, expenses and the related disclosure of contingent liabilities. These assumptions, estimates and judgments are based on our historical experience and assumptions that we believe to be reasonable at the time. However, because future events and their effects cannot be determined with certainty, the determination of estimates requires the exercise of judgment. Our critical accounting estimates are those which require assumptions to be made about matters that are highly uncertain.

Different estimates could have a material effect on our financial results. Judgments and uncertainties affecting the application of these policies and estimates may result in materially different amounts being reported under different conditions or circumstances. Historically, however, recorded estimates have not differed materially from actual results. Significant items subject to such judgments include: the carrying value of property, plant and equipment; unbilled revenues; the valuation of derivative instruments; the valuation of insurance and claims liabilities; the valuation of allowances for receivables and deferred income taxes; regulatory assets and liabilities; liabilities recorded for income tax exposures; litigation; contingencies; the valuation of AROs; assets and liabilities related to employee benefits and intangible assets. Refer to our Form 10-K for the year ended December 31, 2017 for a complete listing of our critical accounting policies and estimates. There have been no material changes to these critical accounting policies and estimates.

ELECTRIC SALES AND CUSTOMERS (a)
	DPL		DP&L (b)
	Three months ended		Three months ended
	March 31,		March 31,
	2018	2017	2018	2017
Electric Sales (millions of kWh)	2,550	3,825	813	985
Billed electric customers (end of period)	523,280	520,265	523,280	520,265

(a) This table contains wholesale sales in the PJM market and to other utilities.

(b) Excluded from DP&L electric sales are 2,746 KWh of power relating to generation sales for the three months ended March 31, 2017, as the generation business was classified as a discontinued operation for the period listed.

Item 3 – Quantitative and Qualitative Disclosures about Market Risk

See the “MARKET RISK” section in Item 2 of this Part I, which is incorporated by reference into this item.

Item 4 – Controls and Procedures

Disclosure Controls and Procedures

DPL and DP&L, under the supervision and with the participation of its management, including our Chief Executive Officer (CEO) and Chief Financial Officer (CFO), evaluated the effectiveness of its “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) under the Securities Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of March 31, 2018, to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act, is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our CEO and CFO, as appropriate, to allow timely decisions regarding required disclosures.

Changes in Internal Controls over Financial Reporting

There were no changes that occurred during the fiscal quarter covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Management and our Boards of Directors are committed to the continued improvement of DPL's and DP&L's overall systems of internal control over financial reporting.

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Part II – Other Information

Item 1 – Legal Proceedings

In the normal course of business, we are subject to various lawsuits, actions, claims, and other proceedings. We are also, from time to time, involved in other reviews, investigations and proceedings by governmental and regulatory agencies regarding our business, certain of which may result in adverse judgments, settlements, fines, penalties, injunctions or other relief. We have accrued in our Financial Statements for litigation and claims where it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. We believe the amounts provided in our Financial Statements, as prescribed by GAAP, for these matters are adequate in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims and other matters (including those matters noted below), and to comply with applicable laws and regulations will not exceed the amounts reflected in our Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided for in our Financial Statements, cannot be reasonably determined, but could be material.

Our Form 10-K for the fiscal year ended December 31, 2017 and the Notes to DPL’s Consolidated Financial Statements and DP&L’s Financial Statements included therein contain descriptions of certain legal proceedings in which we are or were involved. The information in or incorporated by reference into this Item 1 to Part II is limited to certain recent developments concerning our legal proceedings and new legal proceedings, since the filing of such Form 10-K, and should be read in conjunction with such Form 10-K.

The following information is incorporated by reference into this Item: information about the legal proceedings contained in Part I, Item 2 - Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note 3 – Regulatory Matters of Notes to DPL's Condensed Consolidated Financial Statements and Note 3 – Regulatory Matters of Notes to DP&L's Condensed Financial Statements of this Quarterly Report on Form 10-Q.

Item 1A – Risk Factors

A listing of the risk factors that we consider to be the most significant to a decision to invest in our securities is provided in our Form 10-K for the fiscal year ended December 31, 2017. As of March 31, 2018, there have been no material changes with respect to the risk factors disclosed in our Form 10-K. If any of the events described in our risk factors occur, it could have a material effect on our results of operations, financial condition and cash flows.

The risks and uncertainties described in our risk factors are not the only ones we face. In addition, new risks may emerge at any time, and we cannot predict those risks or estimate the extent to which they may affect our business or financial performance. Our risk factors should be read in conjunction with the other detailed information concerning DPL and DP&L set forth in the Notes to DPL’s and DP&L’s Financial Statements and the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” sections included in our filings.

Item 2 – Unregistered Sale of Equity Securities and Use of Proceeds

None

Item 3 – Defaults Upon Senior Securities

None

Item 4 – Mine Safety Disclosures

Not applicable.

Item 5 – Other Information

None

86

Item 6 – Exhibits

DPL Inc.	DP&L	Exhibit Number	Exhibit	Location
X		31(a)	Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/Rule 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 31(a)
X		31(b)	Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/Rule 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 31(b)
	X	31(c)	Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/Rule 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 31(c)
	X	31(d)	Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/Rule 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 31(d)
X		32(a)	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 32(a)
X		32(b)	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 32(b)
	X	32(c)	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 32(c)
	X	32(d)	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 32(d)
X	X	101.INS	XBRL Instance	Filed herewith as Exhibit 101.INS
X	X	101.SCH	XBRL Taxonomy Extension Schema	Filed herewith as Exhibit 101.SCH
X	X	101.CAL	XBRL Taxonomy Extension Calculation Linkbase	Filed herewith as Exhibit 101.CAL
X	X	101.DEF	XBRL Taxonomy Extension Definition Linkbase	Filed herewith as Exhibit 101.DEF
X	X	101.LAB	XBRL Taxonomy Extension Label Linkbase	Filed herewith as Exhibit 101.LAB
X	X	101.PRE	XBRL Taxonomy Extension Presentation Linkbase	Filed herewith as Exhibit 101.PRE

Exhibits referencing File No. 1-9052 have been filed by DPL Inc. and those referencing File No. 1-2385 have been filed by The Dayton Power and Light Company.

87

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, DPL Inc. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		DPL Inc.
		(Registrant)
Date:	May 8, 2018	/s/ Gustavo D. Pimenta
		Gustavo D. Pimenta
		Chief Financial Officer
		(principal financial officer)
	May 8, 2018	/s/ Karin M. Nyhuis
		Karin M. Nyhuis
		Controller
		(principal accounting officer)

88

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, The Dayton Power and Light Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		The Dayton Power and Light Company
		(Registrant)
Date:	May 8, 2018	/s/ Gustavo D. Pimenta
		Gustavo D. Pimenta
		Vice President and Chief Financial Officer
		(principal financial officer)
	May 8, 2018	/s/ Karin M. Nyhuis
		Karin M. Nyhuis
		Controller
		(principal accounting officer)

89

EX-31.A

Exhibit 31(a)

CERTIFICATIONS

I, Craig L. Jackson, certify that:

1. I have reviewed this quarterly report on Form 10-Q of DPL Inc. ;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 8, 2018

/s/ Craig L. Jackson

Craig L. Jackson

President and Chief Executive Officer

EX-31.B

Exhibit 31(b)

CERTIFICATIONS

I, Gustavo D. Pimenta, certify that:

1. I have reviewed this quarterly report on Form 10-Q of DPL Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 8, 2018

/s/ Gustavo D. Pimenta

Gustavo D. Pimenta

Chief Financial Officer

EX-31.C

 Exhibit 31(c)

CERTIFICATIONS

I, Craig L. Jackson, certify that:

1. I have reviewed this quarterly report on Form 10-Q of The Dayton Power and Light Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 8, 2018

/s/ Craig L. Jackson

Craig L. Jackson

President and Chief Executive Officer

EX-31.D

Exhibit 31(d)

CERTIFICATIONS

I, Gustavo D. Pimenta, certify that:

1. I have reviewed this quarterly report on Form 10-Q of The Dayton Power and Light Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 8, 2018

/s/ Gustavo D. Pimenta

Gustavo D. Pimenta

Vice President and Chief Financial Officer

EX-32.A

Exhibit 32(a)

DPL Inc.

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

The undersigned officer of DPL Inc. (the “Issuer”) hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Issuer’s Quarterly Report on Form 10-Q for the period ended March 31, 2018, which this certificate accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that the information contained therein fairly presents, in all material respects, the financial condition and results of operations of the Issuer as of the dates and for the periods expressed therein.

A signed original of this written statement required by Section 906 of the Sarbanes-Oxley Act of 2002, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this statement required by Section 906 of the Sarbanes-Oxley Act of 2002, has been provided to the Issuer and will be retained by the Issuer and furnished to the Securities and Exchange Commission or its staff upon request.

Signed:

/s/ Craig L. Jackson

Craig L. Jackson

President and Chief Executive Officer

Date: May 8, 2018

The foregoing certificate is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Issuer’s Annual Report or as a separate disclosure document.

EX-32.B

Exhibit 32(b)

DPL Inc.

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

The undersigned officer of DPL Inc. (the “Issuer”) hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Issuer’s Quarterly Report on Form 10-Q for the period ended March 31, 2018, which this certificate accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that the information contained therein fairly presents, in all material respects, the financial condition and results of operations of the Issuer as of the dates and for the periods expressed therein.

A signed original of this written statement required by Section 906 of the Sarbanes-Oxley Act of 2002, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this statement required by Section 906 of the Sarbanes-Oxley Act of 2002, has been provided to the Issuer and will be retained by the Issuer and furnished to the Securities and Exchange Commission or its staff upon request.

Signed:

/s/ Gustavo D. Pimenta

Gustavo D. Pimenta

Chief Financial Officer

Date: May 8, 2018

The foregoing certificate is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Issuer’s Annual Report or as a separate disclosure document.

EX-32.C

Exhibit 32(c)

The Dayton Power and Light Company

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

The undersigned officer of The Dayton Power and Light Company (the “Issuer”) hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Issuer’s Quarterly Report on Form 10-Q for the period ended March 31, 2018, which this certificate accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that the information contained therein fairly presents, in all material respects, the financial condition and results of operations of the Issuer as of the dates and for the periods expressed therein.

A signed original of this written statement required by Section 906 of the Sarbanes-Oxley Act of 2002, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this statement required by Section 906 of the Sarbanes-Oxley Act of 2002, has been provided to the Issuer and will be retained by the Issuer and furnished to the Securities and Exchange Commission or its staff upon request.

Signed:

/s/ Craig L. Jackson

Craig L. Jackson

President and Chief Executive Officer

Date: May 8, 2018

The foregoing certificate is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Issuer’s Annual Report or as a separate disclosure document.

EX-32.D

Exhibit 32(d)

The Dayton Power and Light Company

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

The undersigned officer of The Dayton Power and Light Company (the “Issuer”) hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Issuer’s Quarterly Report on Form 10-Q for the period ended March 31, 2018, which this certificate accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that the information contained therein fairly presents, in all material respects, the financial condition and results of operations of the Issuer as of the dates and for the periods expressed therein.

A signed original of this written statement required by Section 906 of the Sarbanes-Oxley Act of 2002, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this statement required by Section 906 of the Sarbanes-Oxley Act of 2002, has been provided to the Issuer and will be retained by the Issuer and furnished to the Securities and Exchange Commission or its staff upon request.

Signed:

/s/ Gustavo D. Pimenta

Gustavo D. Pimenta

Vice President and Chief Financial Officer

Date: May 8, 2018

The foregoing certificate is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Issuer’s Annual Report or as a separate disclosure document.

XML

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2018	May 08, 2018
Entity Registrant Name	DPL INC
Entity Central Index Key	0000787250
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	2018
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	0000027430
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

XML

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	102.0
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	28.0
General taxes	22.4	24.2
Impairment of Long-Lived Assets Held-for-use	0.0	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)	0.0
Interest expense	(28.0)	(27.3)
Charge for early redemption of debt	(0.7)	0.0
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	196.0	190.1
Cost of revenues:
Net fuel cost	0.9	0.0
Net purchased power cost	83.8	81.1
Total cost of revenues	84.7	81.1
Gross margin	111.3	109.0
Operating expenses:
Operation and maintenance	32.2	38.0
Depreciation and amortization	18.6	18.1
General taxes	19.3	18.9
Impairment of Long-Lived Assets Held-for-use	0.0	66.3
Other	0.0	19.4
Other Operating Income (Expense), Net	12.4	0.0
Total operating expenses	82.5	75.0
Operating loss	28.8	34.0
Other income / (expense), net
Investment loss	(0.1)	0.0
Interest expense	(8.2)	(7.6)
Charge for early redemption of debt	(0.5)	0.0
Other expense	(0.7)	(1.4)
Total other expense, net	(9.5)	(9.0)
Loss from continuing operations before income tax	19.3	25.0
Income tax benefit from continuing operations	3.6	8.0
Net loss from continuing operations	15.7	17.0
Loss from discontinued operations	0.0	(88.7)
Income tax benefit for discontinued operations	0.0	(29.9)
Net income from discontinued operations	0.0	(58.8)
Net loss	$ 15.7	$ (41.8)

XML

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	0.2
Reclassification to earnings, net of income tax	0.0	(0.1)
AOCI reclassed to Retained Earnings, net of tax	(1.0)
Total change in fair value of available-for-sale securities	(1.0)	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	1.0
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	(0.3)
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), Reclassification Adjustment from AOCI, after Tax	0.0	(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	0.2
Reclassification to earnings, net of income tax	0.0	(0.1)
AOCI reclassed to Retained Earnings, net of tax	(1.1)	0.0
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)	1.0
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	0.0	(1.1)
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), Reclassification Adjustment from AOCI, after Tax	0.0	(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	0.0	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)	$ 0.0
Pension and postretirement activity:
Other comprehensive income	(1.0)
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)

XML

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	$ 0.0
Income tax (expense) benefit on reclassification to earnings	0.0	0.0
AOCI reclassed to Retained Earnings, income tax	0.6	0.0
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	0.2
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax	0.0	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	0.0
Income tax (expense) benefit on reclassification to earnings	0.0	0.0
AOCI reclassed to Retained Earnings, income tax	0.6	0.0
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	0.6
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax	0.0	0.3
Income tax (expense)/benefit on reclassification of earnings related to pension and postretirement activity	$ (0.2)	$ (1.3)

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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	0.0	250.3
Total current assets	372.5	525.5
Property, plant & equipment:
Property, plant & equipment	1,589.0	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	20.0	10.0
Accounts payable	71.5	70.1
Accrued taxes	84.5	80.0
Accrued interest	34.1	16.4
Security deposits	22.4	21.8
Regulatory liabilities, current	8.5	14.8
Insurance and claims costs	3.0	3.0
Other current liabilities	25.9	42.8
Liabilities Held for Sale, Current	0.0	13.2
Total current liabilities	375.5	276.8
Non-current liabilities:
Long-term debt	1,471.0	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	101.0
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	0.0
Other paid-in capital	2,375.0	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	1.0	5.2
Restricted cash	0.9	0.4
Accounts receivable, net	73.0	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	20.0	10.0
Accounts payable	50.0	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	642.0
Deferred taxes	134.3	131.0
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

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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

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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	28.0
Charge for early retirement of debt	0.7	0.0
Deferred income taxes	(41.7)	(4.7)
Impairment of Long-Lived Assets Held-for-use	0.0	66.4
Gain (Loss) on Disposition of Business	(13.6)	0.0
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	(66.0)
Accrued interest payable	17.6	15.9
Security deposits	0.6	17.6
Increase (Decrease) in Self Insurance Reserve	0.0	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	0.0
Payments for Removal Costs	(14.5)	0.0
Insurance proceeds	2.8	1.2
Other investing activities, net	(0.5)	0.2
Net cash provided by investing activities	195.4	(40.0)
Cash flows from financing activities:
Repayments of Lines of Credit	(15.0)	0.0
Proceeds from Lines of Credit	25.0	0.0
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	7.0	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	0.0
Non-cash capital contribution	45.1	0.0
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	0.0
Deferred income taxes	3.6	0.4
Impairment of Long-Lived Assets Held-for-use	0.0	66.3
Gain (Loss) on Disposition of Business	(12.4)	0.0
Gain (Loss) on Sale of Assets and Asset Impairment Charges	0.0	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)	0.0
Other investing activities, net	(0.3)	0.1
Net cash provided by investing activities	(39.4)	(34.0)
Cash flows from financing activities:
Repayments of Lines of Credit	(15.0)	0.0
Proceeds from Lines of Credit	25.0	0.0
Retirement of long-term debt	(61.1)	(1.1)
Payments of Ordinary Dividends, Common Stock	(23.8)	(9.0)
Issuance of short-term debt - related party	0.0	30.0
Repayments of Related Party Debt	0.0	(35.0)
Proceeds from Contributions from Parent	80.0	0.0
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

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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 a6,000-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. Transition method: Retrospective for presentation of non-service cost expense. Prospective for the change in 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. Transition method: retrospective.	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. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2017-12, Derivatives and Hedging (Topic 815): Targeted improvements to Accounting for Hedging Activities	The standard updates the hedge accounting model to expand the ability to hedge nonfinancial and financial risk components, reduce complexity, and ease certain documentation and assessment requirements. When facts and circumstances are the same as at the previous quantitative test, a subsequent quantitative effectiveness test is not required. The standard also eliminates the requirement to separately measure and report hedge ineffectiveness. For cash flow hedges, this means that the entire change in the fair value of a hedging instrument will be recorded in other comprehensive income and amounts deferred will be reclassified to earnings in the same income statement line as the hedged item. Transition method: modified retrospective with the cumulative effect adjustment recorded to the opening balance of retained earnings as of the initial application date. Prospective for presentation and disclosures.	January 1, 2019. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
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. Transition method: modified retrospective.	January 1, 2019. Early adoption is permitted.	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. Transition method: various.	January 1, 2020. Early adoption is permitted only as of January 1, 2019.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2016-02, 2018-01, Leases (Topic 842)	See "2016-02, Leases (Topic 842)" below.	January 1, 2019. Early adoption is permitted.	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&Lis 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 a6,000square 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. Transition method: Retrospective for presentation of non-service cost expense. Prospective for the change in 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. Transition method: retrospective.	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. Early adoption is permitted.	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. Transition method: modified retrospective with the cumulative effect adjustment recorded to the opening balance of retained earnings as of the initial application date. Prospective for presentation and disclosures.	January 1, 2019. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our 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. Transition method: modified retrospective.	January 1, 2019. Early adoption is permitted.	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. Transition method: various.	January 1, 2020. Early adoption is permitted only as of January 1, 2019.	We are currently evaluating the impact of adopting the standard on our financial statements.
2016-02, 2018-01, Leases (Topic 842)	See "2016-02, Leases (Topic 842)" below.	January 1, 2019. Early adoption is permitted.	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.

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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 endedMarch 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	)

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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.

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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 (MW)	Gross Plant In Service ($ in millions)		Accumulated Depreciation ($ in millions)		Construction Work in Process ($ in millions)
Jointly-owned production units
Conesville - Unit 4	16.5	129	$	0.6	$	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.

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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 (through remaining life)	10.0	%
				Weighted-average cost of capital	7.0	%
Killen	$	7.9	Discounted cash flow	Pre-tax operating margin (through remaining life)	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.

XML

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 (in thousands)		Sales (in thousands)		Net Purchases/ (Sales) (in thousands)
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 (in thousands)		Sales (in thousands)			Net Purchases/ (Sales) (in thousands)
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.

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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 endedMarch 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 DPL6.75% 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 than2.50 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 TotalConsolidated 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 TotalConsolidated 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.

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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 endedMarch 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 endedMarch 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).

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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

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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.

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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 SO₂, 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.

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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

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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.

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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 assetswas $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.

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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.

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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 assetswas $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.

XML

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 assetswas $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.

XML

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 assetswas $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.

XML

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 a6,000-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. Transition method: Retrospective for presentation of non-service cost expense. Prospective for the change in 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. Transition method: retrospective.	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. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2017-12, Derivatives and Hedging (Topic 815): Targeted improvements to Accounting for Hedging Activities	The standard updates the hedge accounting model to expand the ability to hedge nonfinancial and financial risk components, reduce complexity, and ease certain documentation and assessment requirements. When facts and circumstances are the same as at the previous quantitative test, a subsequent quantitative effectiveness test is not required. The standard also eliminates the requirement to separately measure and report hedge ineffectiveness. For cash flow hedges, this means that the entire change in the fair value of a hedging instrument will be recorded in other comprehensive income and amounts deferred will be reclassified to earnings in the same income statement line as the hedged item. Transition method: modified retrospective with the cumulative effect adjustment recorded to the opening balance of retained earnings as of the initial application date. Prospective for presentation and disclosures.	January 1, 2019. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
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. Transition method: modified retrospective.	January 1, 2019. Early adoption is permitted.	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. Transition method: various.	January 1, 2020. Early adoption is permitted only as of January 1, 2019.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2016-02, 2018-01, Leases (Topic 842)	See "2016-02, Leases (Topic 842)" below.	January 1, 2019. Early adoption is permitted.	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&Lis 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 a6,000square 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. Transition method: Retrospective for presentation of non-service cost expense. Prospective for the change in 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. Transition method: retrospective.	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. Early adoption is permitted.	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. Transition method: modified retrospective with the cumulative effect adjustment recorded to the opening balance of retained earnings as of the initial application date. Prospective for presentation and disclosures.	January 1, 2019. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our 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. Transition method: modified retrospective.	January 1, 2019. Early adoption is permitted.	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. Transition method: various.	January 1, 2020. Early adoption is permitted only as of January 1, 2019.	We are currently evaluating the impact of adopting the standard on our financial statements.
2016-02, 2018-01, Leases (Topic 842)	See "2016-02, Leases (Topic 842)" below.	January 1, 2019. Early adoption is permitted.	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.

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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.

XML

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. Transition method: Retrospective for presentation of non-service cost expense. Prospective for the change in 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. Transition method: retrospective.	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. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2017-12, Derivatives and Hedging (Topic 815): Targeted improvements to Accounting for Hedging Activities	The standard updates the hedge accounting model to expand the ability to hedge nonfinancial and financial risk components, reduce complexity, and ease certain documentation and assessment requirements. When facts and circumstances are the same as at the previous quantitative test, a subsequent quantitative effectiveness test is not required. The standard also eliminates the requirement to separately measure and report hedge ineffectiveness. For cash flow hedges, this means that the entire change in the fair value of a hedging instrument will be recorded in other comprehensive income and amounts deferred will be reclassified to earnings in the same income statement line as the hedged item. Transition method: modified retrospective with the cumulative effect adjustment recorded to the opening balance of retained earnings as of the initial application date. Prospective for presentation and disclosures.	January 1, 2019. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
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. Transition method: modified retrospective.	January 1, 2019. Early adoption is permitted.	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. Transition method: various.	January 1, 2020. Early adoption is permitted only as of January 1, 2019.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2016-02, 2018-01, Leases (Topic 842)	See "2016-02, Leases (Topic 842)" below.	January 1, 2019. Early adoption is permitted.	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

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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 endedMarch 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	)

XML

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 (MW)	Gross Plant In Service ($ in millions)		Accumulated Depreciation ($ in millions)		Construction Work in Process ($ in millions)
Jointly-owned production units
Conesville - Unit 4	16.5	129	$	0.6	$	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

XML

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 (through remaining life)	10.0	%
				Weighted-average cost of capital	7.0	%
Killen	$	7.9	Discounted cash flow	Pre-tax operating margin (through remaining life)	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

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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 (in thousands)		Sales (in thousands)		Net Purchases/ (Sales) (in thousands)
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 (in thousands)		Sales (in thousands)			Net Purchases/ (Sales) (in thousands)
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.

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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 endedMarch 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.

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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%

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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

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Business Segments (Tables)

3 Months Ended

Mar. 31, 2018

Segment Reporting Information [Line Items]

Financial Reporting for Reportable Business Segments

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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.

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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	)

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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	)

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Summary of Significant Accounting Policies (Narrative) (Details) $ in Millions		3 Months Ended
	Jan. 01, 2018 USD ($)	Mar. 31, 2018 USD ($) mi² employee customer generating_facility segment	Mar. 31, 2017 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
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		$ (1.0)
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		$ 1.0		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)	0.0
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		1.0
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

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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)	$ 0.0
Gain (Loss) on Sale of Assets and Asset Impairment Charges	(0.6)	(19.4)
Unbilled revenue	12.1		$ 18.0
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)	0.0
Gain (Loss) on Sale of Assets and Asset Impairment Charges	0.0	(19.4)
Unbilled revenue	12.1		18.0
Customer receivables	49.8		44.2
Amounts due from partners in jointly owned stations	3.8		0.0
Amounts due from affiliates	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
Plant materials and supplies	7.0		6.9
Other	0.6		0.4
Total inventories, at average cost	7.6		$ 7.3
Other Operating Income (Expense), Net	(12.4)	0.0
Other Operating Income (Expense) [Member]
Supplemental Financial Information [Line Items]
Gain (Loss) on Disposition of Business	13.6	0.0
Insurance Recoveries	0.0	(1.2)
Gain (Loss) on Sale of Assets and Asset Impairment Charges	0.6	19.4
Other Cost and Expense, Operating	0.7	0.0
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

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Supplemental Financial Information (Reclassification out of ACOI) (Details) - USD ($) $ in Millions		3 Months Ended
	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		(28.0)	(27.3)
Revenue		293.2	323.9
Purchased power		(97.8)	(102.0)
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)	(9.0)
AOCI reclassed to Retained Earnings before tax	$ 1.7
Tax expense		(3.6)	(8.0)
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax		0.0	(88.7)
Discontinued Operation, Tax Effect of Discontinued Operation		0.0	29.9
Net loss		15.7	(41.8)
Interest expense		(8.2)	(7.6)
Revenue		196.0	190.1
Purchased power		(83.8)	(81.1)
Operating Expenses		(82.5)	(75.0)
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	(0.1)
AOCI reclassed to Retained Earnings before tax		(1.6)	0.0
Tax expense		0.6	0.0
Net loss		(1.0)	(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	(0.1)
AOCI reclassed to Retained Earnings before tax		(1.7)	0.0
Tax expense		0.6	0.0
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	1.0
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
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		0.0	1.8
Discontinued Operation, Tax Effect of Discontinued Operation		0.0	(0.6)
Net loss		(0.3)	1.0
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

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Supplemental Financial Information (Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions		3 Months Ended
	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		(1.0)
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)	0.0
Other comprehensive income		0.0	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	1.0	1.0
Other comprehensive loss before reclassifications		0.0
Amounts reclassified from accumulated other comprehensive income / (loss)		0.0
AOCI reclassed to Retained Earnings, net of tax		(1.0)	$ 0.0
Other comprehensive income		(1.0)
Balance, end of period		0.0
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		0.0
Amounts reclassified from accumulated other comprehensive income / (loss)		0.0
AOCI reclassed to Retained Earnings, net of tax		(1.1)
Other comprehensive income		(1.1)
Balance, end of period		0.0
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		0.0
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		0.0
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		0.0
Amounts reclassified from accumulated other comprehensive income / (loss)		0.1
AOCI reclassed to Retained Earnings, net of tax		0.0
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		0.0
Amounts reclassified from accumulated other comprehensive income / (loss)		0.9
AOCI reclassed to Retained Earnings, net of tax		0.0
Other comprehensive income		0.9
Balance, end of period		$ (37.8)

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Regulatory Matters (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018 USD ($)
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%

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Property, Plant and Equipment (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018 USD ($) generating_facility power_plant MW	Mar. 31, 2017 USD ($)	Dec. 31, 2017 USD ($)
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	0.0
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	39.4
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	9.0
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	$ 0.0
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	$ 0.0
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		$ 8.0
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	$ 0.0	$ (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

XML

Fair Value (Narrative) (Details) - USD ($) $ in Millions		3 Months Ended		12 Months Ended
	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		$ 1.0
Long-term debt, earliest maturities		2019
Long-term debt, latest maturities		2061
Unrealized Gains and Immaterial Unrealized Losses in AOCI, Before Tax				$ 1.6
Unrealized gains and immaterial unrealized losses in AOCI, after tax				1.0
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	$ 0.0
Long-term debt, earliest maturities		2020
Long-term debt, latest maturities		2061
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%

XML

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	0.0
Real Estate Funds [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.0	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

XML

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	0.2
Total Assets	0.3	0.5
Total Derivative Liabilities	0.0	0.1
Total Liabilities	0.0	0.1
Level 1 [Member] | Commodity Contract - FTR [Member]
Total Derivative Assets		0.2
Total Derivative Liabilities	0.0	0.0
Level 1 [Member] | Forward Contract Power [Member]
Total Derivative Assets		0.0
Total Derivative Liabilities	0.0	0.0
Level 1 [Member] | Interest Rate Contract [Member]
Total Derivative Assets	0.0	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	0.0
Total Assets	0.3	0.3
Total Liabilities	0.0	0.0
Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Interest Rate Contract [Member]
Total Derivative Assets	0.0	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		0.0
Total Derivative Liabilities	0.0	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		0.0
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	0.0
Total Derivative Assets	0.0	0.0
Total Assets	0.0	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		0.0
Total Derivative Liabilities	0.1	0.3
Level 3 [Member] | Forward Contract Power [Member]
Total Derivative Assets		0.0
Total Derivative Liabilities	0.0	0.0
Level 3 [Member] | Interest Rate Contract [Member]
Total Derivative Assets	0.0	0.0
Total Derivative Liabilities		0.0
Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.0	0.0
Total Derivative Assets	0.0	0.0
Total Assets	0.0	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	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	0.0
Money Market Funds [Member] | Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.0	0.0
Money Market Funds [Member] | Level 3 [Member]
Total Master Trust Assets, Fair Value	0.0	0.0
Money Market Funds [Member] | Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.0	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	0.0
Equity Securities [Member] | Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.0	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	0.0
Equity Securities [Member] | Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.0	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	0.0
Debt Securities [Member] | Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.0	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	0.0
Debt Securities [Member] | Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.0	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	0.0
Hedge Funds [Member] | Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.0	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	0.0
Hedge Funds [Member] | Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.0	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	0.0
Tangible Assets [Member] | Level 1 [Member]
Total Master Trust Assets, Fair Value	0.0	0.0
Tangible Assets [Member] | Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.0	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	0.0
Tangible Assets [Member] | Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.0	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	0.0
Debt [Member] | Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt	0.0	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

XML

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	0.0	$ 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		0.0
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		0.0
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		0.0
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		0.0
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		8.0
Property, Plant and Equipment, Net	1,304.8		$ 1,301.4
Impairment of Long-Lived Assets Held-for-use	0.0	$ 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)

XML

Derivative Instruments and Hedging Activities (Narrative) (Details)	3 Months Ended
	Mar. 31, 2018 USD ($) Number_of_interest_rate_swaps	Mar. 29, 2018 USD ($)	Dec. 31, 2017 USD ($)
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

XML

Derivative Instruments and Hedging Activities (Outstanding Derivative Instruments) (Details)	Mar. 31, 2018 USD ($) MWh	Mar. 29, 2018 USD ($)	Dec. 31, 2017 USD ($) MMBTU MWh
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

XML

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	0.0	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	$ 0.0
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	18.0	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	$ 0.0	(4.3)
Net gains / (losses) associated with current period hedging transactions	0.0	0.0
Ending accumulated derivative gain / (loss) in AOCI	0.0	1.8
Portion expected to be reclassified to earnings in the next twelve months	$ 0.0
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	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	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	0.0	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	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	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	$ 0.0

XML

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	$ (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	0.0
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	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	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	4.0
Purchased Power [Member] | Natural Gas [Member]
Derivative, Gain (Loss) on Derivative, Net	$ 0.1	$ (0.3)

XML

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	0.0	(8.7)
Derivative, Collateral, Obligation to Return Cash	0.0	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	0.0	(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		0.0
Derivative Asset, Fair Value, Amount Offset Against Collateral		0.0
Cash Flow Hedging [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member]
Derivative Liability, Fair Value		9.0
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	0.0
Derivative, Collateral, Obligation to Return Cash	0.0
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	0.0
Derivative, Collateral, Obligation to Return Cash	0.0	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		0.0
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	0.0
Derivative, Collateral, Right to Reclaim Cash	0.0	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		0.0
Liability position offset by the asset position of counterparties with master netting agreements		0.0
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		0.0
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	0.0	(3.7)
Derivative, Collateral, Right to Reclaim Cash	(0.1)	0.0
Liability position offset by the asset position of counterparties with master netting agreements	0.0	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		0.0
Derivative, Collateral, Obligation to Return Cash		0.0
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

XML

Debt (Narrative) (Details)	3 Months Ended		6 Months Ended		12 Months Ended
	Mar. 31, 2018 USD ($) fiscal_quarter debt_covenant	Mar. 31, 2017 USD ($)	Dec. 31, 2018	Jul. 03, 2018	Sep. 30, 2018 USD ($)	Apr. 30, 2018 USD ($)	Mar. 30, 2018 USD ($)	Jan. 03, 2018	Dec. 31, 2017 USD ($)	Aug. 03, 2015 USD ($)
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										$ 200,000,000.0
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					$ 750,000,000.0
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					$ 750,000,000.0
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%

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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				$ 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	$ 1,471.0				1,700.4
Long-term debt, earliest maturities	2019
Long-term debt, latest maturities	2061
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)				(2.0)
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	$ 583.1				642.0
Long-term debt, earliest maturities	2020
Long-term debt, latest maturities	2061
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. 01, 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	$ 140.0				200.0
Debt instrument maturity year	Aug. 01, 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. 01, 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. 01, 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					70.0
Debt instrument maturity year	Jul. 31, 2020
Senior unsecured due in October 2019 - 6.75% [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 200.0			$ 200.0	200.0
Debt instrument maturity year	Oct. 01, 2019
Debt instrument interest percentage	6.75%
Senior unsecured due in October 2021 - 7.25% [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 780.0				780.0
Debt instrument maturity year	Oct. 01, 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. 01, 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%

XML

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	$ 0.0
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%

XML

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	$ 5.0
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	0.0	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	5.0
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	0.0	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

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Benefit Plans (Estimated Future Benefit Payments and Medicare Part D Reimbursements) (Details) - Pension [Member] $ in Millions	Mar. 31, 2018 USD ($)
2016	$ 21.3
2017	28.2
2018	27.9
2019	27.6
2020	27.3
2021 - 2025	131.3
THE DAYTON POWER AND LIGHT COMPANY [Member]
2016	21.3
2017	28.2
2018	27.9
2019	27.6
2020	27.3
2021 - 2025	$ 131.3

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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	$ 750,000,000.0
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

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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	2019
Debt maturity, latest	2040
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

XML

Business Segments (Narrative) (Details) - THE DAYTON POWER AND LIGHT COMPANY [Member]	3 Months Ended
	Mar. 31, 2018 mi² customer segment
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

XML

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)	$ 0.0
External customer revenues	293.2	323.9
Intersegment revenues	0.0	0.0
Total revenues	293.2	323.9
Depreciation and amortization	20.1	28.0
Fuel Costs	33.8	54.1
Depreciation and amortization	20.1	28.0
Impairment of Long-Lived Assets Held-for-use	0.0	66.4
Interest expense	28.0	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	196.0	190.1
Depreciation and amortization	18.6	18.1
Impairment of Long-Lived Assets Held-for-use	0.0	0.0
Interest expense	8.2	7.6
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	19.3	25.0
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	95.0	131.8
Intersegment revenues	0.0	0.0
Total revenues	95.0	131.8
Depreciation and amortization	1.5	7.0
Impairment of Long-Lived Assets Held-for-use	0.0	66.3
Interest expense	0.0	0.0
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	71.0	(86.8)
Capital expenditures	1.7	14.1
Total assets	228.9		275.0
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	3.0	3.7
Depreciation and amortization	0.0	2.9
Impairment of Long-Lived Assets Held-for-use	0.0	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	1.0	1.0
Total assets	580.4		468.0
Adjustments and Eliminations [Member]
Segment Reporting Information [Line Items]
External customer revenues	0.0	0.0
Intersegment revenues	(0.8)	(1.7)
Total revenues	(0.8)	(1.7)
Depreciation and amortization	0.0	0.0
Impairment of Long-Lived Assets Held-for-use	0.0	0.0
Interest expense	0.0	(0.1)
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	0.0	0.0
Capital expenditures	0.0	0.0
Total assets	(580.9)		(383.2)
Subsidiaries [Member]
Segment Reporting Information [Line Items]
Gain (Loss) on Disposition of Business	(12.4)	0.0
Depreciation and amortization	18.6	18.1
Fuel Costs	0.9	0.0
Depreciation and amortization	18.6	23.5
Impairment of Long-Lived Assets Held-for-use	0.0	66.3
Interest expense	8.2	7.6
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	19.3	25.0
Net income / (loss) from continuing operations	15.7	17.0
Discontinued operations, net of tax	0.0	(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	0.0
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

XML

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	73.0	$ 79.4
Transmission and Distribution [Member]
RTO Revenue	11.1
RTO Capacity Revenue	1.9
Revenues	196.0
Generation [Member]
RTO Revenue	1.8
RTO Capacity Revenue	27.3
Revenues	95.0
Corporate, Non-Segment [Member]
RTO Revenue	0.0
RTO Capacity Revenue	0.0
Revenues	3.0
Adjustments and Eliminations [Member]
RTO Revenue	0.0
RTO Capacity Revenue	0.0
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	196.0
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	0.0
Other Revenues [Member] | Transmission and Distribution [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0
Other non-606 revenue	0.0
Other Revenues [Member] | Generation [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0
Other non-606 revenue	0.0
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	0.0
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	0.0
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	0.0
Derivative Revenue	0.0
Wholesale Revenue [Member] | Adjustments and Eliminations [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0
Derivative Revenue	0.0
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	161.0
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	0.0
Other non-606 revenue	0.0
Retail Revenue [Member] | Corporate, Non-Segment [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0
Other non-606 revenue	0.0
Retail Revenue [Member] | Adjustments and Eliminations [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	(0.2)
Other non-606 revenue	0.0
Retail Revenue [Member] | Subsidiaries [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	161.2
Other non-606 revenue	$ 9.2

XML

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)	$ 0.0
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	0.0	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)	0.0
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	19.3	25.0
Impairment of Long-Lived Assets Held-for-use	0.0	$ 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

XML

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	$ 0.0	$ 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	$ 0.0	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

XML

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		$ 750.0
Loss from discontinued operations	$ 0.0	(88.7)
Discontinued Operation, Tax Effect of Discontinued Operation	0.0	(29.9)
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent	0.0	$ (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		$ 750.0
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		121.0
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)

XML

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	$ 25.0