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 June 30, 2017

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 August 7, 2017, 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 June 30, 2017

		Page No.
Glossary of Terms		5
Forward-Looking Statements		8
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	11
	Condensed Consolidated Statements of Comprehensive Income / (Loss)	12
	Condensed Consolidated Balance Sheets	13
	Condensed Consolidated Statements of Cash Flows	14
	Notes to Condensed Consolidated Financial Statements	15
	The Dayton Power and Light Company
	Condensed Statements of Operations	42
	Condensed Statements of Comprehensive Income / (Loss)	43
	Condensed Balance Sheets	44
	Condensed Statements of Cash Flows	45
	Notes to Condensed Financial Statements	46
Item 2	Management’s Discussion and Analysis of Financial Condition and Operations	70
	Electric Sales and Customers	109
Item 3	Quantitative and Qualitative Disclosures about Market Risk	109
Item 4	Controls and Procedures	109

3

DPL Inc. and The Dayton Power and Light Company

Table of Contents (cont.)

Quarterly Report on Form 10-Q

Quarter Ended June 30, 2017

		Page No.
Part II Other Information
Item 1	Legal Proceedings	110
Item 1A	Risk Factors	110
Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	110
Item 3	Defaults Upon Senior Securities	110
Item 4	Mine Safety Disclosures	110
Item 5	Other Information	111
Item 6	Exhibits	112
Other
	Signatures	113

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GLOSSARY OF TERMS 

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

Term	Definition
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 peaking 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. DP&L’s capacity is located in the “rest of” RTO area of PJM.
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 DP&L units operate under the CP construct effective June 1, 2016.
CPP	Clean Power Plan
D.C. Circuit Court	United States Court of Appeals for the District of Columbia Circuit
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
ESP 1	ESP approved by PUCO order dated June 24, 2009
ESP 2	ESP approved by PUCO order dated September 4, 2013. The Ohio Supreme Court ruled that it was invalid. DP&L withdrew its ESP 2 on July 27, 2016 and filed to reinstate previously authorized rates from ESP 1
ESP 3	ESP filed with the PUCO by DP&L on February 22, 2016 and an amended application filed on October 11, 2016
FASC	Financial Accounting Standards Board (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, 2016, which was filed on February 28, 2017
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
FTR	Financial Transmission Right

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GLOSSARY OF TERMS (cont.)
Term	Definition
GAAP	Generally Accepted Accounting Principles in the United States of America
Generation Separation	Divestiture by DP&L of its generation assets to 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.
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
NERC	North American Electric Reliability Corporation
NOx	Nitrogen Oxide
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
PJM	PJM Interconnection, LLC, an RTO
PUCO	Public Utilities Commission of Ohio
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
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. 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
TCRR-N	Transmission Cost Recovery Rider - Nonbypassable
USEPA	U.S. Environmental Protection Agency
USD	U.S. dollar

6

GLOSSARY OF TERMS (cont.)
Term	Definition
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. SBU	U. S. Strategic Business Unit, AES’ reporting unit covering the businesses in the United States, including DPL

7

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:

• abnormal or severe weather and catastrophic weather-related damage;

• unusual maintenance or repair requirements;

• changes in fuel costs and purchased power, coal, environmental emission allowances, natural gas and other commodity prices;

• volatility and changes in markets for electricity and other energy-related commodities;

• performance of our suppliers;

• increased competition and deregulation in the electric utility industry;

• availability and price of capacity;

• state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, emission levels, rate structures or tax laws;

• changes in environmental laws and regulations to which DPL and its subsidiaries are subject;

• the development and operation of RTOs, including PJM to which DP&L has given control of its transmission functions;

• changes in our purchasing processes, pricing, delays, contractor and supplier performance and availability;

• significant delays associated with large construction projects;

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

• changes in accounting rules and the effect of accounting pronouncements issued periodically by accounting standard-setting bodies;

• financial market conditions, changes in interest rates and changes in our credit ratings and availability and cost of capital;

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

• the outcomes of litigation and regulatory investigations, proceedings or inquiries;

• general economic conditions; 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, 2016 and the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section in such report and in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2017

8

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

9

FINANCIAL STATEMENTS

DPL INC.

10

DPL INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
	Three months ended June 30,						Six months ended June 30,
$ in millions	2017			2016			2017			2016
Revenues	$	298.1		$	328.3		$	622.0		$	692.3
Cost of revenues:
Fuel	54.0			60.2			108.1			127.1
Purchased power	77.4			96.9			179.4			218.8
Total cost of revenues	131.4			157.1			287.5			345.9
Gross margin	166.7			171.2			334.5			346.4
Operating expenses:
Operation and maintenance	82.1			77.2			168.4			165.7
Depreciation and amortization	26.5			36.0			54.5			69.4
General taxes	24.0			21.6			48.2			42.6
Fixed-asset impairment	—			235.5			66.4			235.5
Loss / (gain) on asset disposal	(3.2		)	—			16.2			0.1
Other	0.3			—			(0.9		)	—
Total operating expenses	129.7			370.3			352.8			513.3
Operating income / (loss)	37.0			(199.1		)	(18.3		)	(166.9		)
Other income / (expense), net
Investment income	0.1			0.3			0.1			0.2
Interest expense	(27.4		)	(26.0		)	(54.3		)	(52.3		)
Charge for early redemption of debt	(0.3		)	—			(0.3		)	(2.6		)
Other deductions	(0.6		)	(0.3		)	(1.6		)	(0.7		)
Total other expense, net	(28.2		)	(26.0		)	(56.1		)	(55.4		)
Income / (loss) from continuing operations before income tax	8.8			(225.1		)	(74.4		)	(222.3		)
Income tax expense / (benefit) from continuing operations	8.3			(88.3		)	(23.2		)	(87.7		)
Net income / (loss) from continuing operations	0.5			(136.8		)	(51.2		)	(134.6		)
Discontinued operations (Note 12)
Loss from discontinued operations	—			—			—			(0.7		)
Gain from disposal of discontinued operations	—			—			—			49.2
Income tax expense for discontinued operations	—			—			—			18.9
Net income from discontinued operations	—			—			—			29.6
Net income / (loss)	$	0.5		$	(136.8	)	$	(51.2	)	$	(105.0	)

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

11

DPL INC.
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME / (LOSS)
	Three months ended June 30,						Six months ended June 30,
$ in millions	2017			2016			2017			2016
Net income / (loss)	$	0.5		$	(136.8	)	$	(51.2	)	$	(105.0	)
Available-for-sale securities activity:
Change in fair value of available-for-sale securities, net of income tax expense of $0.0, $0.0, $0.0 and $(0.1) for each respective period	0.1			(0.1		)	0.3			0.1
Reclassification to earnings, net of income tax expense of $0.0, $0.0, $0.0 and $0.0 for each respective period	—			0.1			(0.1		)	—
Total change in fair value of available-for-sale securities	0.1			—			0.2			0.1
Derivative activity:
Change in derivative fair value, net of income tax (expense) / benefit of $(0.6), $4.7, $(3.4) and $7.1 for each respective period	1.1			(8.5		)	6.1			13.0
Reclassification to earnings, net of income tax (expense) / benefit of $0.0, $5.9, $(0.5) and $10.7 for each respective period	(0.2		)	(10.8		)	1.0			(19.0		)
Total change in fair value of derivatives	0.9			(19.3		)	7.1			(6.0		)
Pension and postretirement activity:
Prior service cost for the period, net of income tax benefit of $0.0, $0.0, $0.2 and $0.0 for each respective period	—			—			(0.3		)	—
Net loss for period, net of income tax benefit of $0.0, $0.0, $0.7 and $0.0 for each respective period	—			—			(1.2		)	—
Reclassification to earnings, net of income tax expense of $0.0, $0.0, $(0.5) and $(0.2) for each respective period	0.1			0.1			0.9			—
Total change in unfunded pension obligation	0.1			0.1			(0.6		)	—
Other comprehensive income / (loss)	1.1			(19.2		)	6.7			(5.9		)
Net comprehensive income / (loss)	$	1.6		$	(156.0	)	$	(44.5	)	$	(110.9	)

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

12

DPL INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
$ in millions	June 30, 2017			December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents	$	34.1		$	54.6
Restricted cash	1.5			29.0
Accounts receivable, net (Note 2)	99.6			135.1
Inventories (Note 2)	29.3			77.2
Taxes applicable to subsequent years	41.0			81.0
Regulatory assets, current	4.3			0.1
Other prepayments and current assets	29.2			31.8
Assets held for sale - current (Note 13)	68.6			—
Total current assets	307.6			408.8
Property, plant & equipment:
Property, plant & equipment	1,953.4			1,985.6
Less: Accumulated depreciation and amortization	(357.1		)	(334.8		)
	1,596.3			1,650.8
Construction work in process	63.3			116.4
Total net property, plant & equipment	1,659.6			1,767.2
Other non-current assets:
Regulatory assets, non-current	209.5			203.9
Intangible assets, net of amortization	19.0			22.7
Other deferred assets	14.7			16.6
Total other non-current assets	243.2			243.2
Total assets	$	2,210.4		$	2,419.2
LIABILITIES AND SHAREHOLDER'S DEFICIT
Current liabilities:
Current portion of long-term debt (Note 7)	$	50.9		$	29.7
Accounts payable	57.4			113.9
Accrued taxes	154.9			185.1
Accrued interest	17.7			17.7
Security deposits	16.9			15.2
Regulatory liabilities, current	15.0			33.7
Insurance and claims costs	5.4			5.4
Other current liabilities	34.3			50.2
Liabilities held for sale - current (Note 13)	23.2			—
Total current liabilities	375.7			450.9
Non-current liabilities:
Long-term debt (Note 7)	1,786.7			1,828.7
Deferred taxes	257.4			252.4
Taxes payable	42.1			84.6
Regulatory liabilities, non-current	133.1			130.4
Pension, retiree and other benefits	101.8			101.6
Asset retirement obligations	131.7			138.8
Other deferred credits	14.0			19.4
Total non-current liabilities	2,466.8			2,555.9
Commitments and contingencies (Note 10)
Common shareholder's deficit
Common stock:
1,500 shares authorized; 1 share issued and outstanding at June 30, 2017 and December 31, 2016	—			—
Other paid-in capital	2,233.0			2,233.0
Accumulated other comprehensive income	7.0			0.3
Accumulated deficit	(2,872.1		)	(2,820.9		)
Total common shareholder's deficit	(632.1		)	(587.6		)
Total liabilities and shareholder's deficit	$	2,210.4		$	2,419.2

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

13

DPL INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
	Six months ended June 30,
$ in millions	2017			2016
Cash flows from operating activities:
Net loss	$	(51.2	)	$	(105.0	)
Adjustments to reconcile net loss to net cash from operating activities:
Depreciation and amortization	54.5			69.4
Charge for early redemption of debt	0.3			2.6
Deferred income taxes	(1.8		)	(95.9		)
Fixed-asset impairment	66.4			235.5
Gain on sale of business	—			(49.2		)
Loss on asset disposal	16.2			0.1
Changes in certain assets and liabilities:
Accounts receivable	22.4			52.7
Inventories	7.7			21.6
Prepaid taxes	—			0.2
Taxes applicable to subsequent years	40.0			41.7
Deferred regulatory costs, net	(9.1		)	8.0
Accounts payable	(38.4		)	(11.7		)
Accrued taxes payable	(65.3		)	(25.7		)
Accrued interest payable	(0.1		)	(0.8		)
Security deposits	1.7			—
Unamortized investment tax credit	(0.2		)	(0.2		)
Insurance claims costs	(0.1		)	(0.4		)
Pension, retiree and other benefits	2.0			(4.2		)
Other	(4.8		)	(6.3		)
Net cash provided by operating activities	40.2			132.4
Cash flows from investing activities:
Capital expenditures	(66.4		)	(79.1		)
Proceeds from sale of business	—			75.5
Insurance proceeds	0.9			3.2
Purchase of renewable energy credits	(0.1		)	(0.2		)
Decrease / (increase) in restricted cash	27.5			(16.0		)
Other investing activities, net	0.2			0.7
Net cash used in investing activities	(37.9		)	(15.9		)
Cash flows from financing activities:
Retirement of long-term debt	(22.8		)	(75.4		)
Other financing activities, net	—			(0.1		)
Net cash used in financing activities	(22.8		)	(75.5		)
Cash and cash equivalents:
Net change	(20.5		)	41.0
Balance at beginning of period	54.6			32.4
Cash and cash equivalents at end of period	$	34.1		$	73.4
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	51.8		$	51.1
Income taxes paid / (refunded), net	$	—		$	0.1
Non-cash financing and investing activities:
Accruals for capital expenditures	$	9.9		$	8.3

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

14

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 Transmission and Distribution (T&D) segment and the Generation segment. See Note 11 – 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 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 520,000 customers located in West Central Ohio. Additionally, DP&L procures retail SSO electric service on behalf of residential, commercial, industrial and governmental customers in a6,000square mile area of West Central Ohio. DP&L owns undivided interests in multiple coal-fired and peaking electric generating facilities as well as numerous transmission facilities. DP&L sources 100% of the generation for its SSO customers through a competitive bid process. Principal industries located in DP&L’s service territory include automotive, food processing, paper, plastic, manufacturing and defense. DP&L's distribution sales reflect the general economic conditions, seasonal weather patterns, retail competition in our service territory and the market price of electricity. DP&L sells all of its energy and capacity into the wholesale market.

DPL’s other significant subsidiaries include AES Ohio Generation, which owns and operates peaking generating facilities from which it sells all of its energy and capacity into the wholesale market, and MVIC, our captive insurance company that provides insurance services to DPL and our subsidiaries. DPL owns all of the common stock of its subsidiaries.

DPL also has a wholly-owned business trust, DPL Capital Trust II, formed for the purpose of issuing trust capital securities to investors.

DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators while its generation business is deemed competitive under Ohio law. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates, and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs.

DPL and its subsidiaries employed 1,115 people as of June 30, 2017, of which 1,106 were employed by DP&L. Approximately 60% of all DPL employees are under a collective bargaining agreement that expires on October 31, 2017.

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. DP&L has undivided ownership interests in five coal-fired generating facilities, various peaking 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

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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, 2016.

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 June 30, 2017; our results of operations for the three and six months ended June 30, 2017 and 2016 and our cash flows for the six months ended June 30, 2017 and 2016. 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 and six months ended June 30, 2017 may not be indicative of our results that will be realized for the full year ending December 31, 2017.

The preparation of financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the revenues and expenses of the periods reported. Actual results could differ from these estimates. Significant items subject to such estimates and judgments include: the carrying value of property, plant and equipment; unbilled revenues; the valuation of derivative instruments; the valuation of insurance and claims liabilities; the valuation of allowances for receivables and deferred income taxes; regulatory assets and liabilities; 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

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 June 30, 2017 and 2016 were $11.4 million and $11.6 million, respectively. The amounts of such taxes collected for the six months ended June 30, 2017 and 2016 were $23.9 million and $24.5 million, respectively.

New Accounting Pronouncements

The following table provides a brief description of recent accounting pronouncements that could have a material impact on our consolidated financial statements:

Accounting Standard	Description	Date of Adoption	Effect on the financial statements upon adoption
New Accounting Standards Adopted
2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting	The standard simplifies the following aspects of accounting for share-based payments awards: accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, statutory tax withholding requirements, classification of awards as either equity or liabilities and classification of employee taxes paid on statement of cash flows when an employer withholds shares for tax-withholding purposes. Transition method: The recognition of excess tax benefits and tax deficiencies arising from vesting or settlement were applied retrospectively. The elimination of the requirement that excess tax benefits be realized before they are recognized was adopted on a modified retrospective basis with a cumulative adjustment to the opening balance sheet.	January 1, 2017.	The primary effect of adoption was the recognition of excess tax benefits in our provision for income taxes in the period when the awards vest or are settled, rather than in paid-in-capital in the period when the excess tax benefits are realized. We will continue to estimate the number of awards that are expected to vest in our determination of the related periodic compensation cost. The adoption of this standard did not have a material impact on the consolidated financial statements.

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Accounting Standard	Description	Date of Adoption	Effect on the financial statements upon adoption
New Accounting Standards Issued But Not Yet Effective
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.
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. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business	This standard provides guidance to assist the entities with evaluating when a set of transferred assets and activities is a business. Transition method: prospective.	January 1, 2018. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2016-18, Statement of Cash Flows (Topic 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. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory	This standard requires that an entity recognizes the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. Transition method: modified retrospective.	January 1, 2018. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
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, Leases (Topic 842)	The standard creates Topic 842, Leases which supersedes Topic 840, Leases, and introduces a lessee model that brings substantially all leases onto the balance sheet while retaining most of the principles of the existing lessor model in U.S. GAAP and aligning many of those principles with ASC 606, Revenue from Contracts with Customers. Transition method: modified retrospective approach with certain practical expedients.	January 1, 2019. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements. We intend to adopt the standard as of January 1, 2019.
2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-05 Revenue from Contracts with Customers (Topic 606)	See discussion of the ASUs below.	January 1, 2018.	We will adopt the standard on January 1, 2018; see below for the evaluation of the impact of its adoption on the consolidated financial statements.

ASU 2014-09 and its subsequent corresponding updates provide the principles an entity must apply to measure and recognize revenue. The core principle is that an entity shall recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Amendments to the standard were issued that provide further clarification of the principle and to provide certain transition expedients. The standard will replace most existing

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revenue recognition guidance in GAAP, including the guidance on recognizing other income upon the sale or transfer of non-financial assets (including in-substance real estate).

The standard requires retrospective application and allows either a full retrospective adoption in which all of the periods are presented under the new standard or a modified retrospective approach in which the cumulative effect of initially applying the guidance is recognized at the date of initial application. We are currently working toward adopting the standard using the full retrospective method. However, we will continue to assess this conclusion which is dependent on the final impact to the financial statements.

In 2016, we established a cross-functional implementation team and are in the process of evaluating changes to our business processes, systems and controls to support recognition and disclosure under the new standard. At this time, we do not expect any significant impact on our financial systems or a material change to controls as a result of the implementation of the new revenue recognition standard.

We are currently evaluating certain contracts along with our tariff revenue, capacity agreements with PJM and wholesale agreements with PJM. We expect additional contracts to be executed during 2017 that will require assessment under the new standard. Through this assessment, we have identified certain key issues that we are continuing to evaluate in order to complete our assessment of the full population of contracts and be able to assess the overall impact to the financial statements. These issues include: the application of the practical expedient for measuring progress toward satisfaction of a performance obligation, when variable quantities would be considered variable consideration versus an option to acquire additional goods and services, and how to measure progress toward completion for a performance obligation that is a bundle. We are continuing to work with various non-authoritative industry groups, and monitoring the FASB and Transition Resource Group activity, as we finalize our accounting policy on these and other industry specific interpretative issues which is expected in 2017.

Note 2 – Supplemental Financial Information

Accounts receivable and Inventories are as follows at June 30, 2017 and December 31, 2016:

	June 30,			December 31,
$ in millions	2017			2016
Accounts receivable, net:
Unbilled revenue	$	15.5		$	43.0
Customer receivables	62.1			73.9
Amounts due from partners in jointly owned plants	3.6			12.7
Other	19.4			6.7
Provision for uncollectible accounts	(1.0		)	(1.2		)
Total accounts receivable, net	$	99.6		$	135.1
Inventories, at average cost:
Fuel and limestone	$	17.6		$	38.9
Plant materials and supplies	10.4			36.6
Other	1.3			1.7
Total inventories, at average cost	$	29.3		$	77.2

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Accumulated Other Comprehensive Income / (Loss)

The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the three and six months ended June 30, 2017 and 2016 are as follows:

Details about Accumulated Other Comprehensive Income / (Loss) components	Affected line item in the Condensed Consolidated Statements of Operations	Three months ended						Six months ended
		June 30,						June 30,
$ in millions		2017			2016			2017			2016
Gains and losses on Available-for-sale securities activity (Note 5):
	Other income	$	—		$	0.1		$	(0.1	)	$	—
Gains and losses on cash flow hedges (Note 6):
	Interest expense	(0.3		)	(0.3		)	(0.5		)	(0.5		)
	Revenue	0.1			(20.1		)	(1.3		)	(37.3		)
	Purchased power	—			3.7			3.3			8.1
	Total before income taxes	(0.2		)	(16.7		)	1.5			(29.7		)
	Tax expense / (benefit)	—			5.9			(0.5		)	10.7
	Net of income taxes	(0.2		)	(10.8		)	1.0			(19.0		)
Amortization of defined benefit pension items (Note 9):
	Operation and maintenance	0.1			0.1			1.4			0.2
	Tax benefit	—			—			(0.5		)	(0.2		)
	Net of income taxes	0.1			0.1			0.9			—
Total reclassifications for the period, net of income taxes		$	(0.1	)	$	(10.6	)	$	1.8		$	(19.0	)

The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the six months endedJune 30, 2017 are as follows:

$ in millions	Gains / (losses) on available-for-sale securities			Gains / (losses) on cash flow hedges		Change in unfunded pension obligation			Total
Balance January 1, 2017	$	0.6		$	13.1	$	(13.4	)	$	0.3
Other comprehensive income / (loss) before reclassifications	0.3			6.1		(1.5		)	4.9
Amounts reclassified from accumulated other comprehensive income / (loss)	(0.1		)	1.0		0.9			1.8
Net current period other comprehensive income / (loss)	0.2			7.1		(0.6		)	6.7
Balance June 30, 2017	$	0.8		$	20.2	$	(14.0	)	$	7.0

Note 3 – Regulatory Matters

DP&L originally filed its ESP 3 seeking an effective date of January 1, 2017. On October 11, 2016, DP&L amended the application requesting to collect $145.0 million per year for seven years, named the Distribution Modernization Rider ("DMR"). This plan established the terms and conditions for DP&L’s SSO to customers that do not choose a competitive retail electric supplier, and recommended including renewable energy attributes as part of the product that is competitively bid. DP&L sought recovery of approximately $10.5 million of regulatory assets, and proposed a new Distribution Investment Rider to allow DP&L to recover costs associated with future distribution equipment and infrastructure needs. Additionally, the plan established new riders set initially at zero, related to energy reductions from DP&L’s energy efficiency programs, and certain environmental liabilities.

On January 30, 2017, DP&L, in conjunction with various intervening parties, filed a settlement in the ESP 3 case. On March 13, 2017, DP&L, in conjunction with various intervening parties and the staff of the PUCO, filed an amended stipulation in the ESP 3 case, which is subject to PUCO approval. The intervening parties agreed to a

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six-year settlement that provides a framework for energy rates and defines components which include, but are not limited to, the following:

• Bypassable standard offer energy rates for DP&L’s customers based on competitive bid auctions;

• The establishment of a three-year non-bypassable DMR designed to collect $105.0 million in revenue per year to pay debt obligations at DPL and DP&L and position DP&L to modernize and/or maintain its transmission and distribution infrastructure. With PUCO approval, DP&L has the option of extending the duration of the DMR for an additional two years;

• The establishment of a non-bypassable Distribution Investment Rider, set initially at zero, to recover incremental distribution capital investments;

• The establishment of a Smart Grid Rider, set initially at zero, to recover costs of future grid modernization;

• A commitment by us to separate DP&L’s generation assets from its transmission and distribution assets (if approved by FERC) within 180 days after receipt of a PUCO order;

• A commitment to commence a sale process to sell our ownership interests in the Zimmer, Miami Fort and Conesville coal-fired generation plants; and

• Restrictions on DPL making dividend or tax sharing payments, and various other riders and competitive retail market enhancements.

A hearing was held in April 2017 and a final decision by the PUCO is expected in the third quarter of 2017. There can be no assurance that the amended ESP 3 stipulation will be approved as filed or on a timely basis, and if the Amended ESP 3 stipulation is not approved on a timely basis or if the final ESP provides for terms that are more adverse than those submitted in DP&L's amended stipulation, our results of operations, financial condition and cash flows and DPL's ability to meet long-term obligations, in the periods beyond twelve months from the date of this report, could be materially impacted.

In connection with any sale or closure of our generation plants as contemplated by the ESP 3 settlement or otherwise, DPL and DP&L would expect to incur certain cash and non-cash charges, some or all of which could be material to the business and financial condition of DPL and DP&L.

DP&L’s ESP 2 had been approved by the PUCO for the years 2014 - 2016, and permitted DP&L to collect a non-bypassable service stability rider equal to $110.0 million per year for each of those years and required DP&L to conduct competitive bid auctions to procure generation supply for SSO service. The Ohio Supreme Court in a June 2016 opinion stated that the PUCO’s approval of the ESP was reversed. In view of that reversal, DP&L filed a motion to withdraw its ESP 2 and implement rates consistent with those in effect prior to 2014. The PUCO approved DP&L’s withdrawal of ESP 2 and implementation plans. Those rates will be in effect until rates approved as a result of DP&L’s pending ESP 3 are effective. In February 2017, several parties appealed the PUCO orders that approved both the withdrawal and the implementation plans to the Ohio Supreme Court. Those appeals are pending and the outcome and potential financial impact of those appeals cannot be determined at this time. In July 2017, the Office of the Ohio Consumers Counsel filed a motion with the Ohio Supreme Court seeking to stay collection of the reinstated prior rates while the appeals are pending.

Note 4 – Property, Plant and Equipment

Coal-fired facilities

DP&L and certain other Ohio utilities have undivided ownership interests in five coal-fired electric generating facilities and numerous transmission facilities. Certain expenses, primarily fuel costs for the generating units, are allocated to the owners based on their energy usage. The remaining expenses, investments in fuel inventory, plant materials and operating supplies, and capital additions are allocated to the owners in accordance with their respective ownership interests. DP&L’s share of the operations of such facilities is included within the corresponding line in the Condensed Consolidated Statements of Operations, and DP&L’s share of the investment in the facilities is included within Total net property, plant and equipment in the Condensed Consolidated Balance Sheets, except for amounts related to Miami Fort and Zimmer, which are classified as Held for Sale, as described below. Each joint owner provides their own financing for their share of the operations and capital expenditures of the jointly-owned station.

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DP&L’s undivided ownership interest in such facilities at June 30, 2017, is as follows:

	DP&L Share		DPL Carrying Value
	Ownership (%)	Summer Production Capacity (MW)	Gross Plant In Service ($ in millions)		Accumulated Depreciation ($ in millions)		Construction Work in Process ($ in millions)
Jointly-owned production units
Conesville - Unit 4	16.5	129	$	0.6	$	0.6	$	0.7
Killen - Unit 2	67.0	402	8.4		2.5		—
Miami Fort - Units 7 and 8 (a)	36.0	368	31.2		3.1		5.1
Stuart - Units 2 through 4	35.0	606	0.9		0.9		—
Zimmer - Unit 1 (a)	28.1	371	19.9		14.4		5.3
Transmission (at varying percentages)			43.9		11.7		—
Total		1,876	$	104.9	$	33.2	$	11.1

(a) DP&L has entered into an agreement to sell its interest in these units. See Note 13 – Assets and Liabilities Held For Sale for additional information.

Each of the above generating units has SCR and FGD equipment installed.

On January 10, 2017, a high pressure feedwater heater shell failed on Unit 1 at the J.M. Stuart station. As a result, $6.4 million of net book value was written off, resulting in a $3.2 million loss on disposal, net of accrued insurance recoveries being recorded during the first quarter of 2017. This loss was reversed during the second quarter of 2017 due to additional accrued insurance recoveries. On August 2, 2017, the DP&L Board of Directors approved retiring this unit on or around October 1, 2017 and the co-owners of this unit agreed with DP&L to proceed with this retirement. Accordingly, the 202 MWs of capacity associated with Stuart Unit 1 have been removed from the table above.

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 on or before June 1, 2018, and the co-owners of these facilities agreed with DP&L to proceed with this plan of retirement.

On April 21, 2017, DP&L and AES Ohio Generation entered into an agreement for the sale of DP&L’s undivided interests in Zimmer and Miami Fort for $50.0 million in cash and the assumption of certain liabilities, including environmental liabilities. The purchase price is subject to adjustment at closing based on the amount of certain inventories, pre-paid amounts, employment benefits, insurance premiums, property taxes and other costs. The sale is subject to approval by the FERC and is expected to close in the third quarter of 2017. See Note 13 – Assets and Liabilities Held For Sale for additional 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.

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Changes in the Liability for Generation AROs

$ in millions
Balance January 1, 2017	$	138.8
Revisions to cash flow and timing estimates	(4.4		)
Accretion expense	2.0
Settlements	—
Reclassified to Liabilities held for sale	(4.7		)
Balance June 30, 2017	$	131.7

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.

The following table presents the fair value, carrying value and cost of our non-derivative instruments at June 30, 2017 and December 31, 2016. Information about the fair value of our derivative instruments can be found in Note 6 – Derivative Instruments and Hedging Activities.

	June 30, 2017				December 31, 2016
$ in millions	Cost		Fair Value		Cost		Fair Value
Assets
Money market funds	$	0.4	$	0.4	$	0.4	$	0.4
Equity securities	2.6		3.9		2.4		3.4
Debt securities	4.2		4.3		4.4		4.4
Hedge funds	0.1		0.1		—		0.1
Real estate	—		—		0.3		0.3
Tangible assets	0.1		0.1		0.1		0.1
Total Assets	$	7.4	$	8.8	$	7.6	$	8.7
	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities
Long-term debt (a)	$	1,837.3	$	1,926.2	$	1,858.0	$	1,907.7

(a) Amounts exclude immaterial capital lease obligations

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.

Long-term debt

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.

Master Trust Assets

DP&L established Master Trusts 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. These assets are primarily comprised of open-ended mutual funds, which are valued using the net asset value per unit. These investments are recorded at fair value within Other deferred assets on the balance sheets and classified as available-for-sale. Any unrealized gains or losses are recorded in AOCI until the securities are sold.

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DPL had $1.3 million ($0.9 million after tax) of unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at June 30, 2017 and $1.0 million ($0.6 million after tax) of unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at December 31, 2016.

During the six months endedJune 30, 2017, $0.8 million ($0.5 million after tax) of various investments were sold to facilitate the distribution of benefits and the unrealized gains were reversed into earnings. An immaterial amount of unrealized gains are expected to be reversed to earnings as investments are sold over the next twelve months to facilitate the distribution of benefits.

Fair Value Hierarchy

Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. These inputs are then categorized as:

• Level 1 (quoted prices in active markets for identical assets or liabilities);

• Level 2 (observable inputs such as quoted prices for similar assets or liabilities or quoted prices in markets that are not active); or

• Level 3 (unobservable inputs).

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 six months ended June 30, 2017 or 2016.

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The fair value of assets and liabilities at June 30, 2017 and December 31, 2016 and the respective category within the fair value hierarchy for DPL was determined as follows:

Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
$ in millions	Fair value at June 30, 2017		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.4	$	0.4	$	—	$	—
Equity securities	3.9		—		3.9		—
Debt securities	4.3		—		4.3		—
Hedge funds	0.1		—		0.1		—
Tangible assets	0.1		—		0.1		—
Total Master Trust assets	8.8		0.4		8.4		—
Derivative Assets
Forward power contracts	16.4		—		16.4		—
Interest rate hedges	0.9		—		0.9		—
Natural gas	0.3		0.3		—		—
Total Derivative assets	17.6		0.3		17.3		—
Total Assets	$	26.4	$	0.7	$	25.7	$	—
Liabilities
Derivative Liabilities
Interest rate hedges	$	0.2	$	—	$	0.2	$	—
FTRs	0.6		—		—		0.6
Natural gas futures	1.0		1.0		—		—
Forward power contracts	9.8		—		9.8		—
Total Derivative liabilities	11.6		1.0		10.0		0.6
Long-term debt	1,926.3		—		1,908.4		17.9
Total Liabilities	$	1,937.9	$	1.0	$	1,918.4	$	18.5

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Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
$ in millions	Fair value at December 31, 2016		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.4	$	0.4	$	—	$	—
Equity securities	3.4		—		3.4		—
Debt securities	4.4		—		4.4		—
Hedge funds	0.1		—		0.1		—
Real estate	0.3		—		0.3		—
Tangible assets	0.1		—		0.1		—
Total Master Trust assets	8.7		0.4		8.3		—
Derivative assets
Forward power contracts	19.5		—		19.5		—
Interest rate hedges	1.2		—		1.2		—
FTRs	0.1		—		—		0.1
Total Derivative assets	20.8		—		20.7		0.1
Total Assets	$	29.5	$	0.4	$	29.0	$	0.1
Liabilities
Derivative liabilities
Interest rate hedges	$	0.7	$	—	$	0.7	$	—
Forward power contracts	28.5		—		26.0		2.5
Total Derivative liabilities	29.2		—		26.7		2.5
Long-term debt	1,907.7		—		1,889.7		18.0
Total Liabilities	$	1,936.9	$	—	$	1,916.4	$	20.5

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 that are in the Master Trust, which are valued using observable prices based on the end of day net asset value 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 89% 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 loan 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

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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. As a result of changes in our estimates of costs to be incurred for our AROs, we decreased our AROs by $4.4 million in the first six months of 2017. AROs for ash ponds, asbestos, ash landfills, river structures and underground storage tanks decreased by a net amount of $2.4 million and increased by a net amount of $2.3 million during the six months ended June 30, 2017 and 2016, respectively. In addition, there was a $4.7 million decrease in the ARO liability during the six months ended June 30, 2017 related to AROs at Miami Fort and Zimmer being reclassified to Liabilities held for sale - current.

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 14 – Fixed-asset Impairments.

A ruling by the Supreme Court of Ohio on June 20, 2016, lower expectation of future capacity revenue resulting from the most recent PJM capacity auction and a higher anticipated level of environmental compliance costs resulting from third party studies were collectively determined to be an impairment indicator for these assets. As a result, we performed a long-lived asset impairment analysis during the second quarter of 2016 and determined that the carrying amount of Killen and certain DP&L peaking generating facilities were not recoverable. See Note 14 – 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:

$ in millions	Carrying		Fair Value						Gross
	Amount (b)		Level 1		Level 2		Level 3		Loss
	Six months ended June 30, 2017
Assets
Long-lived assets (a)
Stuart	$	42.4	$	—	$	—	$	3.3	$	39.1
Killen	$	35.2	$	—	$	—	$	7.9	$	27.3
	Six months ended June 30, 2016
Assets
Long-lived assets (a)
Killen	$	315.1	$	—	$	—	$	84.3	$	230.8
DP&L peaking facilities	$	9.9	$	—	$	—	$	5.2	$	4.7

(a)See Note 14 – Fixed-asset Impairments for further information

(b)Carrying amount at date of valuation

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The following summarizes the significant unobservable inputs used in the Level 3 measurement on a non-recurring basis during the six months ended June 30, 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	%
				Weighted-average cost of capital	7	%
Killen	$	7.9	Discounted cash flow	Pre-tax operating margin (through remaining life)	22	%
				Weighted-average cost of capital	7	%

The following summarizes the significant unobservable inputs used in the Level 3 measurement on a non-recurring basis during the six months ended June 30, 2016:

$ in millions	Fair value		Valuation technique	Unobservable input	Weighted average
Long-lived assets held and used:
Killen	$	84.3	Discounted cash flow	Annual revenue growth	-11% to 13% (2%)
				Annual pre-tax operating margin	-50% to 67% (6%)
				Weighted-average cost of capital	11%
DP&L peaking facilities	$	5.2	Discounted cash flow	Annual revenue growth	-22% to 17% (-3%)
				Annual pre-tax operating margin	-29% to 24% (-4%)
				Weighted-average cost of capital	7%

Note 6 – Derivative Instruments and Hedging Activities

In the normal course of business, DPL enters into various financial arrangements, including derivative financial instruments. We use derivatives principally to manage the risk of changes in market prices for commodities. 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 normal purchase/normal sale, cash flow hedges or marked to market each reporting period.

At June 30, 2017, DPL had the following outstanding derivative instruments:

Commodity	Accounting Treatment (a)	Unit	Purchases (in thousands)		Sales (in thousands)			Net Purchases/ (Sales) (in thousands)
FTRs	Not designated	MWh	4.7		—			4.7
Natural gas futures	Not designated	Dths	18,490.0		(703.2		)	17,786.8
Forward power contracts	Designated	MWh	810.5		(4,014.2		)	(3,203.7		)
Forward power contracts	Not designated	MWh	1,426.0		(1,630.5		)	(204.5		)
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.

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At December 31, 2016, DPL had the following outstanding derivative instruments:

Commodity	Accounting Treatment (a)	Unit	Purchases (in thousands)		Sales (in thousands)			Net Purchases/ (Sales) (in thousands)
FTRs	Not designated	MWh	2.3		—			2.3
Natural gas futures	Not designated	Dths	1,590.0		—			1,590.0
Forward power contracts	Designated	MWh	342.9		(9,974.5		)	(9,631.6		)
Forward power contracts	Not designated	MWh	2,568.3		(2,020.9		)	547.4
Interest rate swaps	Designated	USD	$	200,000.0	$	—		$	200,000.0

(a)    Refers to whether the derivative instruments have been designated as a cash flow hedge.

Cash Flow Hedges

As part of our risk management processes, we identify the relationships between hedging instruments and hedged items, as well as the risk management objective and strategy for undertaking various hedge transactions. The fair value of cash flow hedges is determined by observable market prices available as of the balance sheet dates and 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.

We have two interest rate swaps to hedge the variable interest on our $200.0 million variable interest rate tax-exempt First Mortgage Bonds. The interest rate swaps have a combined notional amount of $200.0 million and will settle monthly based on a one month LIBOR. We use the income approach to value the swaps, which consists of forecasting future cash flows based on contractual notional amounts and applicable and available market data as of the valuation date. The most common market data inputs used in the income approach include volatilities, spot and forward benchmark interest rates (LIBOR). Forward rates with the same tenor as the derivative instrument being valued are generally obtained from published sources, with these forward rates being assessed quarterly at a portfolio-level for reasonableness versus comparable published rates. We reclassify gains and losses on the swaps out of AOCI and into earnings in those periods in which hedged interest payments occur.

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 table provides information for DPL concerning gains or losses recognized in AOCI for the cash flow hedges for the three and six months ended June 30, 2017 and 2016:

	Three months ended						Three months ended
	June 30, 2017						June 30, 2016
				Interest						Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge
Beginning accumulated derivative gains in AOCI	$	1.8		$	17.5		$	22.5		$	17.5
Net gains / (losses) associated with current period hedging transactions	1.2			(0.1		)	(8.5		)	—
Net gains / (losses) reclassified to earnings
Interest expense	—			(0.2		)	—			(0.2		)
Revenues	—			—			(13.0		)	—
Purchased power	—			—			2.4			—
Ending accumulated derivative gains in AOCI	$	3.0		$	17.2		$	3.4		$	17.3
	Six months ended						Six months ended
	June 30, 2017						June 30, 2016
				Interest						Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge
Beginning accumulated derivative gains / (losses) in AOCI	$	(4.3	)	$	17.4		$	9.2		$	17.5
Net gains associated with current period hedging transactions	6.0			0.1			13.0			—
Net gains / (losses) reclassified to earnings
Interest expense	—			(0.3		)	—			(0.2		)
Revenues	(0.8		)	—			(24.0		)	—
Purchased power	2.1			—			5.2			—
Ending accumulated derivative gains in AOCI	$	3.0		$	17.2		$	3.4		$	17.3
Portion expected to be reclassified to earnings in the next twelve months (a)	$	3.2		$	(0.6	)
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)	9			38

(a)The actual amounts that we reclassify from AOCI to earnings related to power can differ from the estimate above due to market price changes.

Derivatives not designated as hedges

Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for hedge accounting or the normal 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 and six months ended June 30, 2017 and 2016:

For the three months ended June 30, 2017
$ in millions	FTRs			Power			Natural Gas			Total
Change in unrealized gain / (loss)	$	(0.7	)	$	3.7		$	(0.6	)	$	2.4
Realized gain / (loss)	0.1			(0.7		)	—			(0.6		)
Total	$	(0.6	)	$	3.0		$	(0.6	)	$	1.8
Recorded in Income Statement: gain / (loss)
Revenues	$	—		$	(1.0	)	$	—		$	(1.0	)
Purchased power	(0.6		)	4.0			(0.6		)	2.8
Total	$	(0.6	)	$	3.0		$	(0.6	)	$	1.8

For the three months ended June 30, 2016
$ in millions	FTRs		Power			Natural Gas		Total
Change in unrealized gain / (loss)	$	0.2	$	2.6		$	0.5	$	3.3
Realized gain / (loss)	0.2		(2.4		)	0.7		(1.5		)
Total	$	0.4	$	0.2		$	1.2	$	1.8
Recorded in Income Statement: gain / (loss)
Revenues	$	—	$	(5.3	)	$	—	$	(5.3	)
Purchased power	0.4		5.5			1.2		7.1
Total	$	0.4	$	0.2		$	1.2	$	1.8

For the six months ended June 30, 2017
$ in millions	FTRs			Power			Natural Gas			Total
Change in unrealized gain / (loss)	$	(0.7	)	$	3.6		$	(0.7	)	$	2.2
Realized gain / (loss)	0.3			(3.3		)	(0.2		)	(3.2		)
Total	$	(0.4	)	$	0.3		$	(0.9	)	$	(1.0	)
Recorded in Income Statement: gain / (loss)
Revenues	$	—		$	(6.5	)	$	—		$	(6.5	)
Purchased power	(0.4		)	6.8			(0.9		)	5.5
Total	$	(0.4	)	$	0.3		$	(0.9	)	$	(1.0	)

For the six months ended June 30, 2016
$ in millions	FTRs		Power			Natural Gas		Total
Change in unrealized gain / (loss)	$	0.4	$	1.2		$	0.3	$	1.9
Realized gain / (loss)	0.4		(2.9		)	0.5		(2.0		)
Total	$	0.8	$	(1.7	)	$	0.8	$	(0.1	)
Recorded in Income Statement: gain / (loss)
Revenues	$	—	$	(6.6	)	$	—	$	(6.6	)
Purchased power	0.8		4.9			0.8		6.5
Total	$	0.8	$	(1.7	)	$	0.8	$	(0.1	)

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 June 30, 2017
				Gross Amounts Not Offset in the Condensed Consolidated Balance Sheets
$ in millions	Hedging Designation	Gross Fair Value as presented in the Condensed Consolidated Balance Sheets		Financial Instruments with Same Counterparty in Offsetting Position			Cash Collateral			Net Balance Fair Value
Assets
Short-term derivative positions (presented in Other prepayments and current assets)
Forward power contracts	Designated	$	10.2	$	(5.0	)	$	—		$	5.2
Forward power contracts	Not designated	5.1		(4.2		)	—			0.9
Natural gas futures	Not designated	0.1		—			—			0.1
Long-term derivative positions (presented in Other deferred assets)
Interest rate swap	Designated	0.9		—			—			0.9
Natural gas futures	Not designated	0.2		(0.2		)	—			—
Forward power contracts	Not designated	1.1		—			—			1.1
Total assets		$	17.6	$	(9.4	)	$	—		$	8.2
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Designated	$	5.3	$	(5.0	)	$	—		$	0.3
Interest rate swap	Designated	0.2		—			—			0.2
Forward power contracts	Not designated	4.5		(4.2		)	—			0.3
Natural gas futures	Not designated	0.7		—			(0.7		)	—
FTRs	Not designated	0.6		—			—			0.6
Long-term derivative positions (presented in Other deferred credits)
Natural gas futures	Not designated	0.3		(0.2		)	(0.1		)	—
Total liabilities		$	11.6	$	(9.4	)	$	(0.8	)	$	1.4

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Fair Values of Derivative Instruments
at December 31, 2016
				Gross Amounts Not Offset in the Condensed Consolidated Balance Sheets
$ in millions	Hedging Designation	Gross Fair Value as presented in the Condensed Consolidated Balance Sheets		Financial Instruments with Same Counterparty in Offsetting Position			Cash Collateral			Net Balance Fair Value
Assets
Short-term derivative positions (presented in Other prepayments and current assets)
Forward power contracts	Designated	$	11.0	$	(10.5	)	$	—		$	0.5
Forward power contracts	Not designated	6.0		(4.7		)	—			1.3
FTRs	Not designated	0.1		—			—			0.1
Long-term derivative positions (presented in Other deferred assets)
Interest rate swaps	Designated	1.2		—			—			1.2
Forward power contracts	Designated	0.6		(0.6		)	—			—
Forward power contracts	Not designated	1.9		(1.0		)	—			0.9
Total assets		$	20.8	$	(16.8	)	$	—		$	4.0
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Interest rate swaps	Designated	$	0.7	$	—		$	—		$	0.7
Forward power contracts	Designated	16.4		(10.5		)	(5.5		)	0.4
Forward power contracts	Not designated	7.7		(4.7		)	—			3.0
Long-term derivative positions (presented in Other deferred credits)
Forward power contracts	Designated	2.4		(0.6		)	(0.8		)	1.0
Forward power contracts	Not designated	2.0		(1.0		)	—			1.0
Total liabilities		$	29.2	$	(16.8	)	$	(6.3	)	$	6.1

Credit risk-related contingent features

Certain of our OTC commodity derivative contracts are under master netting agreements that contain provisions that require us to post collateral if our credit ratings drop below certain thresholds. We have crossed this threshold and our counterparties could request that we post collateral for our net liability position with them. As of the date of the filing of this report, we have not had to post collateral with any of these counterparties.

The aggregate fair value of DPL’s commodity derivative instruments that were in a MTM loss position at June 30, 2017 was $11.6 million. $0.8 million of collateral was posted directly with third parties and in a broker margin account which offsets our loss positions on the forward contracts. This liability position is further offset by the asset position of counterparties with master netting agreements of $9.4 million. Since our long-term debt is below investment grade, we could have to post collateral for the remaining $1.4 million.

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Note 7 – Long-term Debt

The following table summarizes DPL's outstanding long-term debt.

	Interest		June 30,			December 31,
$ in millions	Rate	Maturity	2017			2016
Term loan - rates from 4.01% - 4.30% (a) and 4.00% - 4.01% (b)		2022	$	442.8		$	445.0
Tax-exempt First Mortgage Bonds	4.8%	2036	91.9			100.0
Tax-exempt First Mortgage Bonds - rates from 1.52% - 1.71% (a) and 1.29% - 1.42% (b)		2020	200.0			200.0
U.S. Government note	4.2%	2061	17.9			18.0
Capital leases			0.3			0.4
Unamortized deferred financing costs			(10.0		)	(10.7		)
Unamortized long-term debt discounts and premiums, net			(5.1		)	(5.5		)
Total long-term debt at consolidated subsidiary			737.8			747.2
Bank term loan - rates from 3.02% - 3.98% (a) and 2.67% - 3.02% (b)		2020	112.5			125.0
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
Unamortized deferred financing costs			(7.7		)	(8.8		)
Unamortized long-term debt discounts and premiums, net			(0.6		)	(0.6		)
Total long-term debt			1,837.6			1,858.4
Less: current portion			(50.9		)	(29.7		)
Long-term debt, net of current portion			$	1,786.7		$	1,828.7

(a) Range of interest rates for the six months endedJune 30, 2017.

(b) Range of interest rates for the year ended December 31, 2016.

(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.

Significant transactions

On May 26, 2017, DP&L commenced a tender offer to purchase any and all of the outstanding 4.8% tax-exempt First Mortgage Bonds at par value (plus accrued and unpaid interest). By June 23, 2017, or the expiration date of the tender, $8.1 million of the outstanding bonds were tendered. On June 26, 2017, DP&L accepted all of the tendered bonds, redeemed and retired them. On July 7, 2017, DP&L notified the Ohio Air Quality Development Authority and the Trustee of the same First Mortgage Bonds, which DP&L was going to call at par value (plus accrued and unpaid interest) $21.9 million of these bonds. As a result, this amount was included in the current portion of long-term debt as of June 30, 2017. On August 7, 2017, DP&L settled this call and subsequently redeemed and retired the bonds. At close of business on August 7,2017 and after considering both the $8.1 million tender and the $21.9 million call, DP&L’s tax-exempt First Mortgage Bonds had an outstanding principal balance of $70.0 million.

Long-term debt covenants and restrictions

DP&L’s unsecured revolving credit agreement and Bond Purchase and Covenants Agreement 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 ratio compares EBITDA to Interest Expense and 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.

On February 21, 2017, DP&L and its lenders amended DP&L’s revolving credit agreement and Bond Purchase and Covenant Agreement. These amendments modified the definition of Consolidated Net Worth (which is used for measuring the Total Debt to Total Capitalization ratio under each of the agreements), to exclude, through March 31, 2018, non-cash charges related directly to impairments of coal generation assets in DP&L's fiscal quarter ending

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December 31, 2016 and thereafter. With this amendment, DP&L’s Total Debt to Total Capitalization ratio for the period ending June 30, 2017 is 0.52 to 1.00. The amendment also changed, for each agreement, the dates after generation separation during which compliance with the Total Capitalization ratio detailed above shall be suspended if long-term indebtedness, as determined by the PUCO, is less than or equal to $750.0 million. This time period was originally January 1, 2017 to December 31, 2017, but is now the twelve months immediately subsequent to the separation of the generation assets from DP&L.

The cost of borrowing under DP&L's unsecured revolving credit agreement and Bond Purchase and Covenants Agreement adjust under certain credit rating scenarios.

DPL’s revolving credit agreement and term loan have two financial covenants. The first financial covenant, a Total Debt to EBITDA ratio, is calculated at the end of each fiscal quarter by dividing total debt at the end of the current quarter by consolidated EBITDA for the four prior fiscal quarters. The second financial covenant, an EBITDA to Interest Expense ratio, is calculated, at the end of each fiscal quarter, by dividing EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period.

The cost of borrowing under DPL's revolving credit agreement and term loan adjust under certain credit rating scenarios. DPL’s revolving credit agreement, term loan, and senior unsecured notes due 2019 restrict dividend payments from DPL to AES.

As of June 30, 2017, DP&L and DPL were in compliance with all debt covenants, including the financial covenants described above.

Substantially all property, plant & equipment of DP&L is subject to the lien of the mortgage securing DP&L’s First and Refunding Mortgage. In July 2017, assets related to the Miami Fort station and the Zimmer station were released from the lien of DP&L's First and Refunding Mortgage in connection with the pending sale. See Note 13 – Assets and Liabilities Held For Sale for additional information.

Note 8 – Income Taxes

The following table details the effective tax rates for the three and six months ended June 30, 2017 and 2016.

	Three months ended		Six months ended
	June 30,		June 30,
	2017	2016	2017	2016
DPL	94.3%	39.2%	31.2%	39.5%

Income tax expense for the six months endedJune 30, 2017 and 2016 was calculated using the estimated annual effective income tax rates for 2017 and 2016 of 30.9% and 38.8%, 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 rates estimated could be materially different from the actual effective tax rates.

The decrease in the annual effective rate compared to the same period in 2016 is primarily due to the forecasted tax expense relating to flow-through depreciation and the projected manufacturer's production deduction.

For the three months ended June 30, 2017, DPL’s current period effective tax rate was greater than the estimated annual effective rate primarily due to the impact of the fixed-asset impairment recorded in the first quarter of 2017. See Note 14 – Fixed-asset Impairments for more information.

Note 9 – Benefit Plans

DP&L sponsors a defined benefit pension plan for the vast 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 $5.0 million in employer contributions during each of the six months ended June 30, 2017 and 2016.

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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 but are still participants in the DP&L plan.

The net periodic benefit cost of the pension benefit plans for the three and six months ended June 30, 2017 and 2016 was:

Net Periodic Benefit Cost	Pension
	Three months ended						Six months ended
	June 30,						June 30,
$ in millions	2017			2016			2017			2016
Service cost	$	1.4		$	1.4		$	2.8		$	2.8
Interest cost	3.5			3.7			7.1			7.4
Expected return on plan assets	(5.7		)	(5.7		)	(11.4		)	(11.4		)
Plan curtailment (a)	—			—			4.1			—
Amortization of unrecognized:
Prior service cost	0.2			0.5			0.6			1.0
Actuarial loss	1.4			1.1			2.7			2.1
Net periodic benefit cost	$	0.8		$	1.0		$	5.9		$	1.9

(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 14 – 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 $15.7 million at June 30, 2017 and $15.8 million at December 31, 2016 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 to be paid during	Pension
2017	$	12.5
2018	25.5
2019	26.0
2020	26.4
2021	26.7
2022 - 2026	139.6

Note 10 – 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 June 30, 2017, DPL had $33.1 million of guarantees on behalf of AES Ohio Generation to third parties for future financial or performance assurance under such agreements. The guarantee arrangements entered into by DPL with these third parties cover 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 $2.3 million at June 30, 2017 and December 31, 2016, respectively.

35

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. If OVEC defaulted on its debt payments, DP&L could be responsible for repayment of its share of OVEC's debt. As of June 30, 2017, this amount was 4.9%, or $71.8 million, of a $1,465.4 million debt obligation that has 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 June 30, 2017, 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, 2016.

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 in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims, tax examinations and other matters 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 June 30, 2017, 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. DP&L has installed emission control technology and is taking other measures to comply with required and anticipated reductions;

• Rules and future rules issued by the USEPA, 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.

Note 11 – Business Segments

DPL currently manages the 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

36

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 520,000 retail customers who are located in a 6,000 square mile area of West Central Ohio. DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates, and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs. The T&D segment includes revenues and costs associated with our investment in OVEC and the historical results of DP&L’s Beckjord, Hutchings Coal, and East Bend generating facilities, which were either closed or sold in prior periods. As these assets will not be transferring to AES Ohio Generation when DP&L’s planned generation separation occurs, they are grouped with the T&D assets for segment reporting purposes. In addition, regulatory deferrals and collections, which include fuel deferrals in historical periods, are included in the T&D segment.

Generation Segment

The Generation segment is comprised of AES Ohio Generation and DP&L’s electric generation business. Beginning in 2001, Ohio law gave consumers the right to choose the electric generation supplier from whom they purchase retail generation services. AES Ohio Generation owns and operates peaking generating facilities, and DP&L owns multiple coal-fired and peaking electric generating facilities. Both AES Ohio Generation and DP&L primarily sell their generated energy and capacity into the PJM wholesale market as DP&L sources all of the generation for its SSO customers through a competitive bid process.

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		Other			Adjustments and Eliminations			DPL Consolidated
Three months ended June 30, 2017
Revenues from external customers	$	167.9	$	127.4	$	2.8		$	—		$	298.1
Intersegment revenues	0.3		—		1.3			(1.6		)	—
Total revenues	$	168.2	$	127.4	$	4.1		$	(1.6	)	$	298.1
Depreciation and amortization	$	18.6	$	4.9	$	3.0		$	—		$	26.5
Interest expense	$	7.8	$	0.2	$	19.4		$	—		$	27.4
Income / (loss) from continuing operations before income tax	$	15.1	$	13.2	$	(19.5	)	$	—		$	8.8
Cash capital expenditures	$	19.4	$	5.1	$	0.5		$	—		$	25.0

37

$ in millions	T&D		Generation			Other			Adjustments and Eliminations			DPL Consolidated
Three months ended June 30, 2016
Revenues from external customers	$	184.7	$	141.4		$	2.2		$	—		$	328.3
Intersegment revenues	0.4		—			0.9			(1.3		)	—
Total revenues	$	185.1	$	141.4		$	3.1		$	(1.3	)	$	328.3
Depreciation and amortization	$	17.6	$	20.8		$	(2.4	)	$	—		$	36.0
Fixed-asset Impairments (Note 14)	$	—	$	857.1		$	(621.6	)	$	—		$	235.5
Interest expense	$	5.6	$	0.1		$	20.3		$	—		$	26.0
Income / (loss) from continuing operations before income tax	$	29.8	$	(861.6	)	$	606.7		$	—		$	(225.1	)
Cash capital expenditures	$	18.1	$	23.3		$	—		$	—		$	41.4

$ in millions	T&D		Generation			Other			Adjustments and Eliminations			DPL Consolidated
Six months ended June 30, 2017
Revenues from external customers	$	357.7	$	259.2		$	5.1		$	—		$	622.0
Intersegment revenues	0.6		—			2.7			(3.3		)	—
Total revenues	$	358.3	$	259.2		$	7.8		$	(3.3	)	$	622.0
Depreciation and amortization	$	36.7	$	11.9		$	5.9		$	—		$	54.5
Fixed-asset Impairments (Note 14)	$	—	$	66.3		$	0.1		$	—		$	66.4
Interest expense	$	15.2	$	0.2		$	38.9		$	—		$	54.3
Income / (loss) from continuing operations before income tax	$	40.1	$	(73.6	)	$	(40.9	)	$	—		$	(74.4	)
Cash capital expenditures	$	45.7	$	19.2		$	1.5		$	—		$	66.4
At June 30, 2017
Total assets	$	1,647.5	$	354.9		$	622.5		$	(414.5	)	$	2,210.4

$ in millions	T&D		Generation			Other			Adjustments and Eliminations			DPL Consolidated
Six months ended June 30, 2016
Revenues from external customers	$	388.9	$	299.6		$	3.8		$	—		$	692.3
Intersegment revenues	0.7		—			2.2			(2.9		)	—
Total revenues	$	389.6	$	299.6		$	6.0		$	(2.9	)	$	692.3
Depreciation and amortization	$	34.8	$	39.4		$	(4.8	)	$	—		$	69.4
Fixed-asset Impairments (Note 14)	$	—	$	857.1		$	(621.6	)	$	—		$	235.5
Interest expense	$	11.0	$	0.2		$	41.2		$	(0.1	)	$	52.3
Income / (loss) from continuing operations before income tax	$	64.0	$	(873.9	)	$	587.6		$	—		$	(222.3	)
Cash capital expenditures	$	42.2	$	36.3		$	0.6		$	—		$	79.1
At December 31, 2016
Total assets	$	1,710.5	$	472.3		$	673.6		$	(437.2	)	$	2,419.2

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Note 12 – Discontinued Operations

On January 1, 2016, DPL closed on the sale of DPLER, its competitive retail business. The sale agreement was signed on December 28, 2015 and DPL recorded a gain on this transaction of $49.2 million in the first quarter of 2016. The gain includes the impact of DPLER’s liability to DP&L that transferred with the sale on January 1, 2016 but was eliminated in consolidation as of December 31, 2015.

Operating activities related to DPLER have been reclassified to "Discontinued operations" in the Condensed Consolidated Statements of Operations for the six months endedJune 30,2016.

The following table summarizes the revenues, cost of revenues, operating expenses and income tax of discontinued operations for the periods indicated:

	Six months ended June 30,
$ in millions	2016
Operating expenses	$	(0.7	)
Loss from discontinued operations before income taxes	(0.7		)
Gain from disposal of discontinued operations	49.2
Income tax expense	18.9
Income on discontinued operations	$	29.6

Cash flows related to discontinued operations are included in our Condensed Consolidated Statements of Cash Flows. Cash flows from operating activities for discontinued operations were $(0.7) million for the six months endedJune 30,2016. Cash flows from investing activities for discontinued operations were $75.5 million for the six months endedJune 30,2016. All cash generated from discontinued operations was paid to DPL through dividends for all periods presented.

Note 13 – Assets and Liabilities Held For Sale

On April 21, 2017, DP&L and AES Ohio Generation entered into an Asset Purchase Agreement with subsidiaries of Dynegy Inc., for the sale of DP&L's undivided interests in the Zimmer Station and the Miami Fort Station for cash and the assumption of certain liabilities, including environmental liabilities. The cash purchase price is subject to adjustment at closing based on the amount of certain inventories, pre-paid amounts, employment benefits, insurance premiums, property taxes and other costs prior to closing. The sale is subject to approval by the FERC and is expected to close in the third quarter of 2017.

Accordingly, the assets and liabilities of Zimmer Station and Miami Fort Station were classified as held for sale as of June 30, 2017, but the plants did not meet the criteria to be reported as discontinued operations. The following table summarizes the major classes of assets and liabilities as of June 30, 2017:

$ in millions	June 30, 2017
Assets
Inventories	$	24.0
Property, plant & equipment, net	44.6
Total assets of the disposal group classified as held for sale in the balance sheet	$	68.6
Liabilities
Accounts payable	$	12.9
Accrued taxes	4.9
Asset retirement obligations	4.7
Other liabilities	0.7
Total liabilities of the disposal group classified as held for sale in the balance sheet	$	23.2

Zimmer Station and Miami Fort Station's results are reflected within continuing operations in the Condensed Consolidated Statements of Operations. The combined income / (loss) from continuing operations before income tax for Zimmer Station and Miami Fort Station was $3.0 million and $(9.7) million for the three months ended

39

June 30, 2017 and 2016, respectively, and $2.2 million and $(16.2) million for the six months ended June 30, 2017 and 2016, respectively. Zimmer Station and Miami Fort Station are included in the Generation segment.

Note 14 – Fixed-asset Impairments

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. The co-owners of these facilities agreed with DP&L to proceed with this plan of retirement. We performed a long-lived asset impairment analysis and determined that the carrying amounts of the Facilities were not recoverable. The asset groups of Stuart Station and Killen Station were determined to have fair values of $3.3 million and $7.9 million, respectively, using the discounted cash flows under the income approach. As a result, we recognized asset impairment expense of $39.1 million and $27.3 million for Stuart Station and Killen Station, respectively.

Additionally, as a result of the decision to retire the Facilities by June 1, 2018, we concluded that inventory at these Facilities is considered obsolete. As a result, we recognized a loss on disposal of $9.8 million and $6.4 million for Stuart Station and Killen Station inventories, respectively, during the first quarter of 2017, which is recorded in Loss on asset disposal in the Condensed Consolidated Statements of Operations.

During the second quarter of 2016, we tested the recoverability of our long-lived assets at certain of our generation facilities at DP&L. A ruling by the Supreme Court of Ohio on June 20, 2016, lower expectation of future capacity revenue resulting from the most recent PJM capacity auction and a higher anticipated level of environmental compliance costs resulting from third party studies were collectively determined to be an impairment indicator for these assets. We performed a long-lived asset impairment analysis and determined that the carrying amount of Killen and certain DP&L peaking generating facilities were not recoverable. The asset groups of Killen and these DP&L peaking generating facilities were determined to have fair values of $84.3 million and $5.2 million, respectively, using the discounted cash flows under the income approach. As a result, we recognized asset impairment expense of $230.8 million and $4.7 million for Killen and these DP&L peaking generating facilities, respectively.

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FINANCIAL STATEMENTS

The Dayton Power and Light Company

41

THE DAYTON POWER AND LIGHT COMPANY
CONDENSED STATEMENTS OF OPERATIONS
	Three months ended June 30,						Six months ended June 30,
$ in millions	2017			2016			2017			2016
Revenues	$	284.1		$	313.7		$	595.2		$	662.9
Cost of revenues:
Fuel	49.9			55.6			100.0			118.5
Purchased power	76.4			96.7			177.2			218.0
Total cost of revenues	126.3			152.3			277.2			336.5
Gross margin	157.8			161.4			318.0			326.4
Operating expenses:
Operation and maintenance	80.9			76.4			163.5			162.5
Depreciation and amortization	22.0			36.8			45.5			71.1
General taxes	23.6			21.1			47.2			41.6
Gain on termination of contract	—			—			—			(27.7		)
Fixed-asset impairment	—			857.1			66.3			857.1
Loss / (gain) on asset disposal	(3.2		)	0.1			16.2			0.2
Total operating expenses	123.3			991.5			338.7			1,104.8
Operating income / (loss)	34.5			(830.1		)	(20.7		)	(778.4		)
Other income / (expense), net:
Investment income, net	0.1			0.3			0.1			0.2
Interest expense	(7.8		)	(5.4		)	(15.4		)	(10.7		)
Charge for early redemption of debt	(0.1		)	—			(0.1		)	—
Other expense, net	(0.4		)	(0.1		)	(1.3		)	(0.3		)
Total other expense, net	(8.2		)	(5.2		)	(16.7		)	(10.8		)
Income / (loss) from operations before income tax	26.3			(835.3		)	(37.4		)	(789.2		)
Income tax expense / (benefit)	10.2			(303.7		)	(11.7		)	(291.3		)
Net income / (loss)	16.1			(531.6		)	(25.7		)	(497.9		)
Dividends on preferred stock	—			0.2			—			0.4
Income / (loss) attributable to common stock	$	16.1		$	(531.8	)	$	(25.7	)	$	(498.3	)

See Notes to Condensed Financial Statements.

These interim statements are unaudited.

42

THE DAYTON POWER AND LIGHT COMPANY
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME / (LOSS)
	Three months ended June 30,						Six months ended June 30,
$ in millions	2017			2016			2017			2016
Net income / (loss)	$	16.1		$	(531.6	)	$	(25.7	)	$	(497.9	)
Available-for-sale securities activity:
Change in fair value of available-for-sale securities, net of income tax expense of $0.0, $0.0, $0.0 and $(0.1) for each respective period	0.1			(0.1		)	0.3			0.1
Reclassification to earnings, net of income tax expense of $0.0, $0.0, $0.0 and $0.0 for each respective period	—			0.1			(0.1		)	—
Total change in fair value of available-for-sale securities	0.1			—			0.2			0.1
Derivative activity:
Change in derivative fair value, net of income tax (expense) / benefit of $(0.6), $4.7, $(3.4) and $(7.0) for each respective period	1.1			(8.5		)	6.2			13.0
Reclassification to earnings, net of income tax (expense) / benefit of $0.0, $5.9, $(0.5) and $10.7 for each respective period	(0.2		)	(10.8		)	0.9			(19.2		)
Total change in fair value of derivatives	0.9			(19.3		)	7.1			(6.2		)
Pension and postretirement activity:
Prior service costs for the period, net of income tax benefit of $0.0, $0.0, $0.6 and $0.0 for each respective period	—			—			(1.1		)	—
Net loss for period, net of income tax benefit of $0.0, $0.0, $0.2 and $0.0 for each respective period	—			—			(0.5		)	—
Reclassification to earnings, net of income tax expense of $(0.3), $(0.4), $(1.6) and $(1.2) for each respective period	0.7			0.7			3.2			1.0
Total change in unfunded pension obligation	0.7			0.7			1.6			1.0
Other comprehensive income / (loss)	1.7			(18.6		)	8.9			(5.1		)
Net comprehensive income / (loss)	$	17.8		$	(550.2	)	$	(16.8	)	$	(503.0	)

See Notes to Condensed Financial Statements.

These interim statements are unaudited.

43

THE DAYTON POWER AND LIGHT COMPANY
CONDENSED BALANCE SHEETS
$ in millions	June 30, 2017			December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents	$	6.1		$	1.6
Restricted cash	1.5			29.0
Accounts receivable, net (Note 2)	95.1			134.6
Inventories (Note 2)	27.7			75.8
Taxes applicable to subsequent years	40.1			79.2
Regulatory assets, current	4.3			0.1
Other prepayments and current assets	28.6			32.4
Assets held for sale - current (Note 13)	68.6			—
Total current assets	272.0			352.7
Property, plant & equipment:
Property, plant & equipment	2,331.7			2,398.6
Less: Accumulated depreciation and amortization	(1,048.3		)	(1,047.9		)
	1,283.4			1,350.7
Construction work in process	51.1			89.9
Total net property, plant & equipment	1,334.5			1,440.6
Other non-current assets:
Regulatory assets, non-current	209.5			203.9
Intangible assets, net of amortization	19.3			23.0
Other deferred assets	13.3			14.9
Total other non-current assets	242.1			241.8
Total assets	$	1,848.6		$	2,035.1
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Current portion of long-term debt (Note 6)	$	26.4		$	4.7
Short-term debt (Note 7)	—			5.0
Accounts payable	54.9			110.5
Accrued taxes	34.0			75.7
Accrued interest	2.1			2.1
Security deposits	16.9			15.2
Regulatory liabilities, current	15.0			33.7
Other current liabilities	33.0			48.3
Liabilities held for sale - current (Note 13)	22.2			—
Total current liabilities	204.5			295.2
Non-current liabilities:
Long-term debt (Note 7)	713.5			744.7
Deferred taxes	157.5			146.3
Taxes payable	42.5			84.1
Regulatory liabilities, non-current	133.1			130.4
Pension, retiree and other benefits	101.8			101.6
Unamortized investment tax credit	16.6			17.7
Asset retirement obligations	129.9			135.2
Other deferred credits	12.6			17.6
Total non-current liabilities	1,307.5			1,377.6
Commitments and contingencies (Note 11)
Common shareholder's equity:
Common stock, at par value of $0.01 per share	0.4			0.4
Other paid-in capital	801.8			810.7
Accumulated other comprehensive loss	(33.6		)	(42.5		)
Accumulated deficit	(432.0		)	(406.3		)
Total common shareholder's equity	336.6			362.3
Total liabilities and shareholder's equity	$	1,848.6		$	2,035.1

See Notes to Condensed Financial Statements.

These interim statements are unaudited.

44

THE DAYTON POWER AND LIGHT COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
	Six months ended June 30,
$ in millions	2017			2016
Cash flows from operating activities:
Net loss	$	(25.7	)	$	(497.9	)
Adjustments to reconcile net loss to net cash from operating activities:
Depreciation and amortization	45.5			71.1
Charge for early redemption of debt	0.1			—
Deferred income taxes	3.2			(308.7		)
Fixed-asset impairment	66.3			857.1
Loss on asset disposal	16.2			0.2
Changes in certain assets and liabilities:
Accounts receivable	26.3			20.5
Inventories	8.0			21.6
Prepaid taxes	—			2.7
Taxes applicable to subsequent years	39.1			40.7
Deferred regulatory costs, net	(9.1		)	8.0
Accounts payable	(38.0		)	(13.8		)
Accrued taxes payable	(75.7		)	(43.3		)
Accrued interest payable	(0.1		)	0.2
Security deposits	1.7			—
Pension, retiree and other benefits	2.0			(4.2		)
Other	(2.3		)	5.3
Net cash provided by operating activities	57.5			159.5
Cash flows from investing activities:
Capital expenditures	(57.6		)	(71.8		)
Purchase of renewable energy credits	(0.1		)	(0.3		)
Decrease / (increase) in restricted cash	27.5			(16.1		)
Insurance proceeds	1.3			3.4
Other investing activities, net	0.2			0.8
Net cash used in investing activities	(28.7		)	(84.0		)
Cash flows from financing activities:
Dividends paid on preferred stock	—			(0.4		)
Return of capital	(9.0		)	—
Redemption of long-term debt	(10.3		)	—
Issuance of short-term debt - related party	30.0			5.0
Repayment of short-term debt - related party	(35.0		)	(40.0		)
Other financing activities, net	—			(0.1		)
Net cash used in financing activities	(24.3		)	(35.5		)
Cash and cash equivalents:
Net change	4.5			40.0
Balance at beginning of period	1.6			5.4
Cash and cash equivalents at end of period	$	6.1		$	45.4
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	13.6		$	8.0
Income taxes paid, net	$	26.2		$	0.1
Non-cash financing and investing activities:
Accruals for capital expenditures	$	9.1		$	8.3

See Notes to Condensed Financial Statements.

These interim statements are unaudited.

45

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&L is a public utility incorporated in 1911 under the laws of Ohio. Beginning in 2001, Ohio law gave Ohio consumers the right to choose the electric generation supplier from whom they purchase retail generation service; however, retail transmission and distribution services are still regulated. DP&L has the exclusive right to provide such transmission and distribution services to approximately 520,000 customers located in West Central Ohio. Additionally, DP&L procures retail SSO electric service on behalf of residential, commercial, industrial and governmental customers in a6,000square mile area of West Central Ohio. DP&L owns undivided interests in multiple coal-fired and peaking electric generating facilities as well as numerous transmission facilities. DP&L sources 100% of the generation for its SSO customers through a competitive bid process. Principal industries located in DP&L’s service territory include automotive, food processing, paper, plastic, manufacturing and defense. DP&L's distribution sales reflect the general economic conditions, seasonal weather patterns, retail competition in our service territory and the market price of electricity. DP&L sells all of its energy and capacity into the wholesale market.DP&L is a subsidiary of DPL.

DP&L has two reportable segments: the Transmission and Distribution (T&D) segment and the Generation segment. See Note 12 – Business Segments for more information relating to these reportable segments.

DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators while its generation business is deemed competitive under Ohio law. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates, and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs.

DP&L employed 1,106 people as of June 30, 2017. Approximately 61% of all employees are under a collective bargaining agreement which expires on October 31, 2017.

Financial Statement Presentation

DP&L does not have any subsidiaries. DP&L has undivided ownership interests in five coal-fired generating facilities, various peaking 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 Statements of Operations.

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, 2016.

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 June 30, 2017; our results of operations for the three and six months ended June 30, 2017 and 2016 and our cash flows for the six months ended June 30, 2017 and 2016. 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 and six months ended June 30, 2017 may not be indicative of our results that will be realized for the full year ending December 31, 2017.

The preparation of financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the revenues and expenses of the periods reported. Actual results could differ from these estimates. Significant items subject to such estimates and judgments include: the carrying value of property, plant and equipment; unbilled

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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; and assets and liabilities related to employee benefits.

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 June 30, 2017 and 2016 were $11.4 million and $11.6 million, respectively. The amounts of such taxes collected for the six months ended June 30, 2017 and 2016 were $23.9 million and $24.5 million, respectively.

New Accounting Pronouncements

The following table provides a brief description of recent accounting pronouncements that could have a material impact on our financial statements:

Accounting Standard	Description	Date of Adoption	Effect on the financial statements upon adoption
New Accounting Standards Adopted
2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting	The standard simplifies the following aspects of accounting for share-based payments awards: accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, statutory tax withholding requirements, classification of awards as either equity or liabilities and classification of employee taxes paid on statement of cash flows when an employer withholds shares for tax-withholding purposes. Transition method: The recognition of excess tax benefits and tax deficiencies arising from vesting or settlement were applied retrospectively. The elimination of the requirement that excess tax benefits be realized before they are recognized was adopted on a modified retrospective basis with a cumulative adjustment to the opening balance sheet.	January 1, 2017.	The primary effect of adoption was the recognition of excess tax benefits in our provision for income taxes in the period when the awards vest or are settled, rather than in paid-in-capital in the period when the excess tax benefits are realized. We will continue to estimate the number of awards that are expected to vest in our determination of the related periodic compensation cost. The adoption of this standard did not have a material impact on the financial statements.
New Accounting Standards Issued But Not Yet Effective
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.
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. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements.
2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business	This standard provides guidance to assist the entities with evaluating when a set of transferred assets and activities is a business. Transition method: prospective.	January 1, 2018. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements.

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Accounting Standard	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. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements.
2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory	This standard requires that an entity recognizes the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. Transition method: modified retrospective.	January 1, 2018. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements.
2016-13, 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, Leases (Topic 842)	The standard creates Topic 842, Leases which supersedes Topic 840, Leases, and introduces a lessee model that brings substantially all leases onto the balance sheet while retaining most of the principles of the existing lessor model in U.S. GAAP and aligning many of those principles with ASC 606, Revenue from Contracts with Customers. Transition method: modified retrospective approach with certain practical expedients.	January 1, 2019. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements. We intend to adopt the standard as of January 1, 2019.
2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-05 Revenue from Contracts with Customers (Topic 606)	See discussion of the ASUs below.	January 1, 2018.	We will adopt the standard on January 1, 2018; see below for the evaluation of the impact of its adoption on the financial statements.

ASU 2014-09 and its subsequent corresponding updates provide the principles an entity must apply to measure and recognize revenue. The core principle is that an entity shall recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Amendments to the standard were issued that provide further clarification of the principle and to provide certain transition expedients. The standard will replace most existing revenue recognition guidance in GAAP, including the guidance on recognizing other income upon the sale or transfer of non-financial assets (including in-substance real estate).

The standard requires retrospective application and allows either a full retrospective adoption in which all of the periods are presented under the new standard or a modified retrospective approach in which the cumulative effect of initially applying the guidance is recognized at the date of initial application. We are currently working toward adopting the standard using the full retrospective method. However, we will continue to assess this conclusion which is dependent on the final impact to the financial statements.

In 2016, we established a cross-functional implementation team and are in the process of evaluating changes to our business processes, systems and controls to support recognition and disclosure under the new standard. At this time, we do not expect any significant impact on our financial systems or a material change to controls as a result of the implementation of the new revenue recognition standard.

We are currently evaluating certain contracts along with our tariff revenue, capacity agreements with PJM and wholesale agreements with PJM. We expect additional contracts to be executed during 2017 that will require

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assessment under the new standard. Through this assessment, we have identified certain key issues that we are continuing to evaluate in order to complete our assessment of the full population of contracts and be able to assess the overall impact to the financial statements. These issues include: the application of the practical expedient for measuring progress toward satisfaction of a performance obligation, when variable quantities would be considered variable consideration versus an option to acquire additional goods and services, and how to measure progress toward completion for a performance obligation that is a bundle. We are continuing to work with various non-authoritative industry groups, and monitoring the FASB and Transition Resource Group activity, as we finalize our accounting policy on these and other industry specific interpretative issues which is expected in 2017.

Note 2 – Supplemental Financial Information

Accounts receivable and Inventories are as follows at June 30, 2017 and December 31, 2016:

	June 30,			December 31,
$ in millions	2017			2016
Accounts receivable, net:
Unbilled revenue	$	15.5		$	43.0
Customer receivables	55.9			71.2
Amounts due from partners in jointly owned plants	3.6			12.7
Amounts due from affiliates	2.1			2.9
Other	19.0			6.0
Provision for uncollectible accounts	(1.0		)	(1.2		)
Total accounts receivable, net	$	95.1		$	134.6
Inventories, at average cost:
Fuel and limestone	$	17.6		$	38.8
Plant materials and supplies	8.8			35.3
Other	1.3			1.7
Total inventories, at average cost	$	27.7		$	75.8

Accumulated Other Comprehensive Income / (Loss)

The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the three and six months ended June 30, 2017 and 2016 are as follows:

Details about Accumulated Other Comprehensive Income / (Loss) components	Affected line item in the Condensed Statements of Operations	Three months ended						Six months ended
		June 30,						June 30,
$ in millions		2017			2016			2017			2016
Gains and losses on Available-for-sale securities activity (Note 5):
	Other income	$	—		$	0.1		$	(0.1	)	$	—
Gains and losses on cash flow hedges (Note 6):
	Interest expense	(0.3		)	(0.3		)	(0.6		)	(0.6		)
	Revenue	0.1			(20.1		)	(1.3		)	(37.2		)
	Purchased power	—			3.7			3.3			8.1
	Total before income taxes	(0.2		)	(16.7		)	1.4			(29.7		)
	Tax expense / (benefit)	—			5.9			(0.5		)	10.5
	Net of income taxes	(0.2		)	(10.8		)	0.9			(19.2		)
Amortization of defined benefit pension items (Note 9):
	Operation and maintenance	1.0			1.1			4.8			2.2
	Tax benefit	(0.3		)	(0.4		)	(1.6		)	(1.2		)
	Net of income taxes	0.7			0.7			3.2			1.0
Total reclassifications for the period, net of income taxes		$	0.5		$	(10.0	)	$	4.0		$	(18.2	)

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The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the six months ended June 30, 2017 are as follows:

$ in millions	Gains / (losses) on available-for-sale securities			Gains / (losses) on cash flow hedges			Change in unfunded pension obligation			Total
Balance January 1, 2017	$	0.7		$	(2.7	)	$	(40.5	)	$	(42.5	)
Other comprehensive income / (loss) before reclassifications	0.3			6.2			(1.6		)	4.9
Amounts reclassified from accumulated other comprehensive income / (loss)	(0.1		)	0.9			3.2			4.0
Net current period other comprehensive income	0.2			7.1			1.6			8.9
Balance June 30, 2017	$	0.9		$	4.4		$	(38.9	)	$	(33.6	)

Note 3 – Regulatory Matters

DP&L originally filed its ESP 3 seeking an effective date of January 1, 2017. On October 11, 2016, DP&L amended the application requesting to collect $145.0 million per year for seven years, named the Distribution Modernization Rider ("DMR"). This plan established the terms and conditions for DP&L’s SSO to customers that do not choose a competitive retail electric supplier, and recommended including renewable energy attributes as part of the product that is competitively bid. DP&L sought recovery of approximately $10.5 million of regulatory assets, and proposed a new Distribution Investment Rider to allow DP&L to recover costs associated with future distribution equipment and infrastructure needs. Additionally, the plan established new riders set initially at zero, related to energy reductions from DP&L’s energy efficiency programs, and certain environmental liabilities.

On January 30, 2017, DP&L, in conjunction with various intervening parties, filed a settlement in the ESP 3 case. On March 13, 2017, DP&L, in conjunction with various intervening parties and the staff of the PUCO, filed an amended stipulation in the ESP 3 case, which is subject to PUCO approval. The intervening parties agreed to a six-year settlement that provides a framework for energy rates and defines components which include, but are not limited to, the following:

• Bypassable standard offer energy rates for DP&L’s customers based on competitive bid auctions;

• The establishment of a three-year non-bypassable DMR designed to collect $105.0 million in revenue per year to pay debt obligations at DPL and DP&L and position DP&L to modernize and/or maintain its transmission and distribution infrastructure. With PUCO approval, DP&L has the option of extending the duration of the DMR for an additional two years;

• The establishment of a non-bypassable Distribution Investment Rider, set initially at zero, to recover incremental distribution capital investments;

• The establishment of a Smart Grid Rider, set initially at zero, to recover costs of future grid modernization;

• A commitment by us to separate DP&L’s generation assets from its transmission and distribution assets (if approved by FERC) within 180 days after receipt of a PUCO order;

• A commitment to commence a sale process to sell our ownership interests in the Zimmer, Miami Fort and Conesville coal-fired generation plants; and

• Restrictions on DPL making dividend or tax sharing payments, and various other riders and competitive retail market enhancements.

A hearing was held in April 2017 and a final decision by the PUCO is expected in the third quarter of 2017. There can be no assurance that the amended ESP 3 stipulation will be approved as filed or on a timely basis, and if the Amended ESP 3 stipulation is not approved on a timely basis or if the final ESP provides for terms that are more adverse than those submitted in DP&L's amended stipulation, our results of operations, financial condition and cash flows and DPL's ability to meet long-term obligations, in the periods beyond twelve months from the date of this report, could be materially impacted.

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In connection with any sale or closure of our generation plants as contemplated by the ESP 3 settlement or otherwise, DPL and DP&L would expect to incur certain cash and non-cash charges, some or all of which could be material to the business and financial condition of DPL and DP&L.

DP&L’s ESP 2 had been approved by the PUCO for the years 2014 - 2016, and permitted DP&L to collect a non-bypassable service stability rider equal to $110.0 million per year for each of those years and required DP&L to conduct competitive bid auctions to procure generation supply for SSO service. The Ohio Supreme Court in a June 2016 opinion stated that the PUCO’s approval of the ESP was reversed. In view of that reversal, DP&L filed a motion to withdraw its ESP 2 and implement rates consistent with those in effect prior to 2014. The PUCO approved DP&L’s withdrawal of ESP 2 and implementation plans. Those rates will be in effect until rates approved as a result of DP&L’s pending ESP 3 are effective. In February 2017, several parties appealed the PUCO orders that approved both the withdrawal and the implementation plans to the Ohio Supreme Court. Those appeals are pending and the outcome and potential financial impact of those appeals cannot be determined at this time. In July 2017, the Office of the Ohio Consumers Counsel filed a motion with the Ohio Supreme Court seeking to stay collection of the reinstated prior rates while the appeals are pending.

Note 4 – Property, Plant and Equipment

Coal-fired facilities

DP&L and certain other Ohio utilities have undivided ownership interests in five coal-fired electric generating facilities and numerous transmission facilities. Certain expenses, primarily fuel costs for the generating units, are allocated to the owners based on their energy usage. The remaining expenses, investments in fuel inventory, plant materials and operating supplies, and capital additions are allocated to the owners in accordance with their respective ownership interests. DP&L’s share of the operations of such facilities is included within the corresponding line in the Condensed Statements of Operations, and DP&L’s share of the investment in the facilities is included within Total net property, plant and equipment in the Condensed Balance Sheets, except for amounts related to Miami Fort and Zimmer, which are classified as Held for Sale, as described below. Each joint owner provides their own financing for their share of the operations and capital expenditures of the jointly-owned station.

DP&L’s undivided ownership interest in such facilities at June 30, 2017, is as follows:

	DP&L Share		DP&L Carrying Value
	Ownership %	Summer Production Capacity (MW)	Gross Plant In Service ($ in millions)		Accumulated Depreciation ($ in millions)		Construction Work in Process ($ in millions)
Jointly-owned production units
Conesville - Unit 4	16.5	129	$	0.6	$	0.6	$	0.7
Killen - Unit 2	67.0	402	8.4		2.5		—
Miami Fort - Units 7 and 8 (a)	36.0	368	31.2		3.1		5.1
Stuart - Units 2 through 4	35.0	606	0.9		0.9		—
Zimmer - Unit 1 (a)	28.1	371	19.9		14.4		5.3
Transmission (at varying percentages)			99.3		67.1		—
Total		1,876	$	160.3	$	88.6	$	11.1

(a) DP&L has entered into an agreement to sell its interest in these units. See Note 13 – Assets and Liabilities Held For Sale for additional information.

Each of the above generating units has SCR and FGD equipment installed.

On January 10, 2017, a high pressure feedwater heater shell failed on Unit 1 at the J.M. Stuart station. As a result, $6.4 million of net book value was written off, resulting in a $3.2 million loss on disposal, net of accrued insurance recoveries being recorded during the first quarter of 2017. This loss was reversed during the second quarter of 2017 due to additional accrued insurance recoveries. On August 2, 2017, the DP&L Board of Directors approved retiring this unit on or around October 1, 2017 and the co-owners of this unit agreed with DP&L to proceed with this retirement. Accordingly, the 202 MWs of capacity associated with Stuart Unit 1 have been removed from the table above.

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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 on or before June 1, 2018, and the co-owners of these facilities agreed with DP&L to proceed with this plan of retirement.

On April 21, 2017, DP&L and AES Ohio Generation entered into an agreement for the sale of DP&L’s undivided interests in Zimmer and Miami Fort for $50.0 million in cash and the assumption of certain liabilities, including environmental liabilities. The purchase price is subject to adjustment at closing based on the amount of certain inventories, pre-paid amounts, employment benefits, insurance premiums, property taxes and other costs. The sale is subject to approval by the FERC and is expected to close in the third quarter of 2017.

AROs

We recognize AROs in accordance with GAAP which requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time those obligations are incurred. Upon initial recognition of a legal liability, costs are capitalized as part of the related long-lived asset and depreciated over the useful life of the related asset. Our legal obligations are associated with the retirement of our long-lived assets, consisting primarily of river intake and discharge structures, coal unloading facilities, loading docks, ice breakers and ash disposal facilities.

Estimating the amount and timing of future expenditures of this type requires significant judgment. Management routinely updates these estimates as additional information becomes available.

Changes in the Liability for Generation AROs

$ in millions
Balance January 1, 2017	$	135.2
Revisions to cash flow and timing estimates	(4.4		)
Accretion expense	2.8
Settlements	—
Reclassified to Liabilities held for sale	(3.7		)
Balance June 30, 2017	$	129.9

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 June 30, 2017 and December 31, 2016. Information about the fair value of our derivative instruments can be found in Note 6 – Derivative Instruments and Hedging Activities.

	June 30, 2017				December 31, 2016
$ in millions	Cost		Fair Value		Cost		Fair Value
Assets
Money market funds	$	0.4	$	0.4	$	0.4	$	0.4
Equity securities	2.6		3.9		2.4		3.4
Debt securities	4.2		4.3		4.4		4.4
Hedge funds	0.1		0.1		—		0.1
Real estate	—		—		0.3		0.3
Tangible assets	0.1		0.1		0.1		0.1
Total assets	$	7.4	$	8.8	$	7.6	$	8.7
	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities
Long-term debt (a)	$	739.6	$	753.0	$	749.0	$	763.5

(a) Amounts exclude immaterial capital lease obligations

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.

Long-term debt

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.

Master Trust Assets

DP&L established Master Trusts 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. These assets are primarily comprised of open-ended mutual funds, which are valued using the net asset value per unit. These investments are recorded at fair value within Other deferred assets on the balance sheets and classified as available-for-sale. Any unrealized gains or losses are recorded in AOCI until the securities are sold.

DP&L had $1.4 million ($0.9 million after tax) of unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at June 30, 2017 and $1.1 million ($0.7 million after tax) in unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at December 31, 2016.

During the six months endedJune 30, 2017, $0.8 million ($0.5 million after tax) of various investments were sold to facilitate the distribution of benefits and the unrealized gains were reversed into earnings. An immaterial amount of unrealized gains are expected to be reversed to earnings as investments are sold over the next twelve months to facilitate the distribution of benefits.

Fair Value Hierarchy

Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. These inputs are then categorized as:

• Level 1 (quoted prices in active markets for identical assets or liabilities);

• Level 2 (observable inputs such as quoted prices for similar assets or liabilities or quoted prices in markets that are not active); or

• Level 3 (unobservable inputs).

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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 six months ended June 30, 2017 or 2016.

The fair value of assets and liabilities at June 30, 2017 and December 31, 2016 and the respective category within the fair value hierarchy for DP&L was determined as follows:

Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
$ in millions	Fair value at June 30, 2017		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.4	$	0.4	$	—	$	—
Equity securities	3.9		—		3.9		—
Debt securities	4.3		—		4.3		—
Hedge funds	0.1		—		0.1		—
Tangible assets	0.1		—		0.1		—
Total Master Trust assets	8.8		0.4		8.4		—
Derivative assets
Natural gas futures	0.3		0.3		—		—
Interest rate hedges	0.9		—		0.9		—
Forward power contracts	16.4		—		16.4		—
Total derivative assets	17.6		0.3		17.3		—
Total assets	$	26.4	$	0.7	$	25.7	$	—
Liabilities
Derivative liabilities
FTRs	$	0.6	$	—	$	—	$	0.6
Interest rate hedges	0.2		—		0.2		—
Natural gas futures	1.0		1.0		—		—
Forward power contracts	9.8		—		9.8		—
Total derivative liabilities	11.6		1.0		10.0		0.6
Long-term debt (a)	753.0		—		735.1		17.9
Total liabilities	$	764.6	$	1.0	$	745.1	$	18.5

(a) Amounts exclude immaterial capital lease obligations

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Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
$ in millions	Fair value at December 31, 2016		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.4	$	0.4	$	—	$	—
Equity securities	3.4		—		3.4		—
Debt securities	4.4		—		4.4		—
Hedge funds	0.1		—		0.1		—
Real estate	0.3		—		0.3		—
Tangible assets	0.1		—		0.1		—
Total Master Trust assets	8.7		0.4		8.3		—
Derivative assets
FTRs	0.1		—		—		0.1
Interest rate hedges	1.2		—		1.2		—
Forward power contracts	19.5		—		19.5		—
Total Derivative assets	20.8		—		20.7		0.1
Total assets	$	29.5	$	0.4	$	29.0	$	0.1
Liabilities
Derivative liabilities
Interest rate hedges	$	0.7	$	—	$	0.7	$	—
Forward power contracts	28.5		—		26.0		2.5
Total Derivative liabilities	29.2		—		26.7		2.5
Long-term debt (a)	763.5		—		745.5		18.0
Total liabilities	$	792.7	$	—	$	772.2	$	20.5

(a) 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 that are in the Master Trust, which are valued using observable prices based on the end of day net asset value 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.

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 loan 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.

Approximately 89% of the inputs to the fair value of our derivative instruments are from quoted market prices.

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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. As a result of changes in our estimates of costs to be incurred for our AROs, we decreased our AROs by $4.4 million in the first six months of 2017. AROs for ash ponds, asbestos, ash landfills, river structures and underground storage tanks decreased by a net amount of $1.6 million and increased by a net amount of $2.3 million during the six months ended June 30, 2017 and 2016, respectively. In addition, there was a $3.7 million decrease in the ARO liability during the six months ended June 30, 2017 related to AROs at Miami Fort and Zimmer being reclassified to Liabilities held for sale - current.

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 14 – Fixed-asset Impairments.

A ruling by the Supreme Court of Ohio on June 20, 2016, lower expectation of future capacity revenue resulting from the most recent PJM capacity auction and a higher anticipated level of environmental compliance costs resulting from third party studies were collectively determined to be an impairment indicator for these assets. As a result, we performed a long-lived asset impairment analysis during the second quarter of 2016 and determined that the carrying amount of Killen and certain DP&L peaking generating facilities were not recoverable. See Note 14 – 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:

$ in millions
	Carrying		Fair Value						Gross
	Amount (b)		Level 1		Level 2		Level 3		Loss
	Six months ended June 30, 2017
Assets
Long-lived assets (a)
Stuart	$	42.3	$	—	$	—	$	3.3	$	39.0
Killen	$	35.2	$	—	$	—	$	7.9	$	27.3
	Six months ended June 30, 2016
Assets
Long-lived assets (a)
Stuart	$	456.4	$	—	$	—	$	164.4	$	292.0
Killen	$	330.5	$	—	$	—	$	84.3	$	246.2
Zimmer	$	429.9	$	—	$	—	$	111.0	$	318.9

(a)See Note 14 – Fixed-asset Impairments for further information

(b)Carrying amount at date of valuation

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The following summarizes the significant unobservable inputs used in the Level 3 measurement on a non-recurring basis during the six months ended June 30, 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	%
				Weighted-average cost of capital	7	%
Killen	$	7.9	Discounted cash flow	Pre-tax operating margin (through remaining life)	22	%
				Weighted-average cost of capital	7	%

The following summarizes the significant unobservable inputs used in the Level 3 measurement on a non-recurring basis during the six months ended June 30, 2016:

$ in millions	Fair value		Valuation technique	Unobservable input	Weighted average
Long-lived assets held and used:
Stuart	$	164.4	Discounted cash flow	Annual revenue growth	-9% to 10% (2%)
				Annual pre-tax operating margin	-29% to 52% (5%)
				Weighted-average cost of capital	9%
Killen	$	84.3	Discounted cash flow	Annual revenue growth	-11% to 13% (2%)
				Annual pre-tax operating margin	-50% to 67% (6%)
				Weighted-average cost of capital	11%
Zimmer	$	111.0	Discounted cash flow	Annual revenue growth	-14% to 13% (1%)
				Annual pre-tax operating margin	-46% to 80% (4%)
				Weighted-average cost of capital	9%

Note 6 – Derivative Instruments and Hedging Activities

In the normal course of business, DP&L enters into various financial arrangements, including derivative financial instruments. We use derivatives principally to manage the risk of changes in market prices for commodities. 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 normal purchase/normal sale, cash flow hedges or marked to market each reporting period.

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At June 30, 2017, DP&L had the following outstanding derivative instruments:

Commodity	Accounting Treatment (a)	Unit	Purchases (in thousands)		Sales (in thousands)			Net Purchases/ (Sales) (in thousands)
FTRs	Not designated	MWh	4.7		—			4.7
Natural gas futures	Not designated	Dths	18,490.0		(703.2		)	17,786.8
Forward power contracts	Designated	MWh	810.5		(4,014.2		)	(3,203.7		)
Forward power contracts	Not designated	MWh	1,426.0		(1,630.5		)	(204.5		)
Interest rate swaps	Designated	USD	$	200,000.0	$	—		$	200,000.0

(a)    Refers to whether the derivative instruments have been designated as a cash flow hedge.

At December 31, 2016, DP&L had the following outstanding derivative instruments:

Commodity	Accounting Treatment (a)	Unit	Purchases (in thousands)		Sales (in thousands)			Net Purchases/ (Sales) (in thousands)
FTRs	Not designated	MWh	2.3		—			2.3
Natural gas futures	Not designated	Dths	1,590.0		—			1,590.0
Forward power contracts	Designated	MWh	342.9		(9,974.5		)	(9,631.6		)
Forward power contracts	Not designated	MWh	2,568.3		(2,037.5		)	530.8
Interest rate swaps	Designated	USD	$	200,000.0	$	—		$	200,000.0

(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 value of cash flow hedges is determined by observable market prices available as of the balance sheet dates and 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.

We have two interest rate swaps to hedge the variable interest on our $200.0 million variable interest rate tax-exempt First Mortgage Bonds. The interest rate swaps have a combined notional amount of $200.0 million and will settle monthly based on a one month LIBOR. We use the income approach to value the swaps, which consists of forecasting future cash flows based on contractual notional amounts and applicable and available market data as of the valuation date. The most common market data inputs used in the income approach include volatilities, spot and forward benchmark interest rates (LIBOR). Forward rates with the same tenor as the derivative instrument being valued are generally obtained from published sources, with these forward rates being assessed quarterly at a portfolio-level for reasonableness versus comparable published rates. We reclassify gains and losses on the swaps out of AOCI and into earnings in those periods in which hedged interest payments occur.

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The following table provides information for DP&L concerning gains or losses recognized in AOCI for the cash flow hedges for the three and six months ended June 30, 2017 and 2016:

	Three months ended						Three months ended
	June 30, 2017						June 30, 2016
				Interest						Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge
Beginning accumulated derivative gains in AOCI	$	1.8		$	1.7		$	22.5		$	1.8
Net gains / (losses) associated with current period hedging transactions	1.2			(0.1		)	(8.5		)	—
Net gains / (losses) reclassified to earnings
Interest expense	—			(0.2		)	—			(0.2		)
Revenues	—			—			(13.0		)	—
Purchased power	—			—			2.4			—
Ending accumulated derivative gains in AOCI	$	3.0		$	1.4		$	3.4		$	1.6
	Six months ended						Six months ended
	June 30, 2017						June 30, 2016
				Interest						Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge
Beginning accumulated derivative gains / (losses) in AOCI	$	(4.3	)	$	1.6		$	9.2		$	2.0
Net gains associated with current period hedging transactions	6.0			0.2			13.0			—
Net gains / (losses) reclassified to earnings
Interest expense	—			(0.4		)	—			(0.4		)
Revenues	(0.8		)	—			(24.0		)	—
Purchased power	2.1			—			5.2			—
Ending accumulated derivative gains in AOCI	$	3.0		$	1.4		$	3.4		$	1.6
Portion expected to be reclassified to earnings in the next twelve months (a)	$	3.2		$	(0.8	)
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)	9			38

(a) The actual amounts that we reclassify from AOCI to earnings related to power can differ from the estimate above due to market price changes.

Derivatives not designated as hedges

Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for hedge accounting or the normal 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 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 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 Statements of Operations of the gains and losses on DP&L's derivatives not designated as hedging instruments for the three and six months ended June 30, 2017 and 2016:

For the three months ended June 30, 2017
$ in millions	FTRs			Power			Natural Gas			Total
Change in unrealized gain / (loss)	$	(0.7	)	$	3.7		$	(0.6	)	$	2.4
Realized gain / (loss)	0.1			(0.7		)	—			(0.6		)
Total	$	(0.6	)	$	3.0		$	(0.6	)	$	1.8
Recorded in Income Statement: gain / (loss)
Revenues	$	—		$	(1.1	)	$	—		$	(1.1	)
Purchased power	(0.6		)	4.1			(0.6		)	2.9
Total	$	(0.6	)	$	3.0		$	(0.6	)	$	1.8

For the three months ended June 30, 2016
$ in millions	FTRs		Power			Natural Gas		Total
Change in unrealized gain / (loss)	$	0.2	$	2.8		0.5		$	3.5
Realized gain / (loss)	0.2		(2.3		)	0.7		(1.4		)
Total	$	0.4	$	0.5		$	1.2	$	2.1
Recorded in Income Statement: gain / (loss)
Revenues	—		(5.1		)	—		(5.1		)
Purchased power	0.4		5.6			1.2		7.2
Total	$	0.4	$	0.5		$	1.2	$	2.1

For the six months ended June 30, 2017
$ in millions	FTRs			Power			Natural Gas			Total
Change in unrealized gain / (loss)	$	(0.7	)	$	3.6		$	(0.7	)	$	2.2
Realized gain / (loss)	0.3			(3.4		)	(0.2		)	(3.3		)
Total	$	(0.4	)	$	0.2		$	(0.9	)	$	(1.1	)
Recorded in Income Statement: gain / (loss)
Revenues	$	—		$	(6.6	)	$	—		$	(6.6	)
Purchased power	(0.4		)	6.8			(0.9		)	5.5
Total	$	(0.4	)	$	0.2		$	(0.9	)	$	(1.1	)

For the six months ended June 30, 2016
$ in millions	FTRs		Power			Natural Gas		Total
Change in unrealized gain / (loss)	$	0.4	$	0.9		0.3		$	1.6
Realized gain / (loss)	0.4		(2.7		)	0.5		(1.8		)
Total	$	0.8	$	(1.8	)	$	0.8	$	(0.2	)
Recorded in Income Statement: gain / (loss)
Revenues	—		(6.6		)	—		(6.6		)
Purchased power	0.8		4.8			0.8		6.4
Total	$	0.8	$	(1.8	)	$	0.8	$	(0.2	)

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.

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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 DP&L’s derivative instruments:

Fair Values of Derivative Instruments
at June 30, 2017
				Gross Amounts Not Offset in the Condensed Balance Sheets
$ in millions	Hedging Designation	Gross Fair Value as presented in the Condensed Balance Sheets		Financial Instruments with Same Counterparty in Offsetting Position			Cash Collateral			Net Balance Fair Value
Assets
Short-term derivative positions (presented in Other prepayments and current assets)
Forward power contracts	Designated	$	10.2	$	(5.0	)	$	—		$	5.2
Forward power contracts	Not designated	5.1		(4.2		)	—			0.9
Natural gas futures	Not designated	0.1		—			—			0.1
Long-term derivative positions (presented in Other deferred assets)
Interest rate swap	Designated	0.9		—			—			0.9
Natural gas futures	Not designated	0.2		(0.2		)	—			—
Forward power contracts	Not designated	1.1		—			—			1.1
Total assets		$	17.6	$	(9.4	)	$	—		$	8.2
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Designated	$	5.3	$	(5.0	)	$	—		$	0.3
Interest rate swaps	Designated	0.2		—			—			0.2
Forward power contracts	Not designated	4.5		(4.2		)	—			0.3
Natural gas futures	Not designated	0.7		—			(0.7		)	—
FTRs	Not designated	0.6		—			—			0.6
Long-term derivative positions (presented in Other deferred credits)
Natural gas futures	Not designated	0.3		(0.2		)	(0.1		)	—
Total liabilities		$	11.6	$	(9.4	)	$	(0.8	)	$	1.4

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Fair Values of Derivative Instruments
at December 31, 2016
				Gross Amounts Not Offset in the Condensed Balance Sheets
$ in millions	Hedging Designation	Gross Fair Value as presented in the Condensed Balance Sheets		Financial Instruments with Same Counterparty in Offsetting Position			Cash Collateral			Net Balance Fair Value
Assets
Short-term derivative positions (presented in Other prepayments and current assets)
Forward power contracts	Designated	$	11.0	$	(10.5	)	$	—		$	0.5
Forward power contracts	Not designated	6.0		(4.7		)	—			1.3
FTRs	Not designated	0.1		—			—			0.1
Long-term derivative positions (presented in Other deferred assets)
Interest rate swaps	Designated	1.2		—			—			1.2
Forward power contracts	Designated	0.6		(0.6		)	—			—
Forward power contracts	Not designated	1.9		(1.0		)	—			0.9
Total assets		$	20.8	$	(16.8	)	$	—		$	4.0
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Designated	$	16.4	$	(10.5	)	$	(5.5	)	$	0.4
Interest rate swaps	Designated	0.7		—			—			0.7
Forward power contracts	Not designated	7.7		(4.7		)	—			3.0
Long-term derivative positions (presented in Other deferred credits)
Forward power contracts	Designated	2.4		(0.6		)	(0.8		)	1.0
Forward power contracts	Not designated	2.0		(1.0		)	—			1.0
Total liabilities		$	29.2	$	(16.8	)	$	(6.3	)	$	6.1

Credit risk-related contingent features

Certain of our OTC commodity derivative contracts are under master netting agreements that contain provisions that require us to post collateral if our credit ratings drop below certain thresholds. We have crossed this threshold and our counterparties could request that we post collateral for our net liability position with them. As of the date of the filing of this report, we have not had to post collateral with any of these counterparties.

The aggregate fair value of DP&L’s commodity derivative instruments that were in a MTM loss position at June 30, 2017 was $11.6 million. $0.8 million of collateral was posted directly with third parties and in a broker margin account which offsets our loss positions on the forward contracts. This liability position is further offset by the asset position of counterparties with master netting agreements of $9.4 million. Since our long-term debt is below investment grade, we could have to post collateral for the remaining $1.4 million.

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Note 7 – Long-term Debt

The following table summarizes DP&L's outstanding long-term debt.

	Interest		June 30,			December 31,
$ in millions	Rate	Maturity	2017			2016
Term loan - rates from 4.01% - 4.30% (a) and 4.00% - 4.01% (b)		2022	$	442.8		$	445.0
Tax-exempt First Mortgage Bonds	4.8%	2036	91.9			100.0
Tax-exempt First Mortgage Bonds - rates from 1.52% - 1.71% (a) and 1.29% - 1.42% (b)		2020	200.0			200.0
U.S. Government note	4.2%	2061	17.9			18.0
Capital leases			0.3			0.4
Unamortized deferred financing costs			(11.0		)	(11.8		)
Unamortized long-term debt discounts			(2.0		)	(2.2		)
Total long-term debt			739.9			749.4
Less: current portion			(26.4		)	(4.7		)
Long-term debt, net of current portion			$	713.5		$	744.7

(a)Range of interest rates for the six months ended June 30, 2017.

(b)Range of interest rates for the year ended December 31, 2016.

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.

Significant transactions

On May 26, 2017, DP&L commenced a tender offer to purchase any and all of the outstanding 4.8% tax-exempt First Mortgage Bonds at par value (plus accrued and unpaid interest). By June 23, 2017, or the expiration date of the tender, $8.1 million of the outstanding bonds were tendered. On June 26, 2017, DP&L accepted all of the tendered bonds, redeemed and retired them. On July 7, 2017, DP&L notified the Ohio Air Quality Development Authority and the Trustee of the same First Mortgage Bonds, which DP&L was going to call at par value (plus accrued and unpaid interest) $21.9 million of these bonds. As a result, this amount was included in the current portion of long-term debt as of June 30, 2017. On August 7, 2017, DP&L settled this call and subsequently redeemed and retired the bonds. At close of business on August 7,2017 and after considering both the $8.1 million tender and the $21.9 million call, DP&L’s tax-exempt First Mortgage Bonds had an outstanding principal balance of $70.0 million.

Debt covenants and restrictions

DP&L’s unsecured revolving credit agreement and Bond Purchase and Covenants Agreement 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 ratio compares EBITDA to Interest Expense and 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.

On February 21, 2017, DP&L and its lenders amended DP&L’s revolving credit agreement and Bond Purchase and Covenant Agreement. These amendments modified the definition of Consolidated Net Worth (which is used for measuring the Total Debt to Total Capitalization ratio under each of the agreements), to exclude, through March 31, 2018, non-cash charges related directly to impairments of coal generation assets in DP&L's fiscal quarter ending December 31, 2016 and thereafter. With this amendment, DP&L’s Total Debt to Total Capitalization ratio for the period ending June 30, 2017 is 0.52 to 1.00. The amendment also changed, for each agreement, the dates after generation separation during which compliance with the Total Capitalization ratio detailed above shall be suspended if long-term indebtedness, as determined by the PUCO, is less than or equal to $750.0 million. This time period was originally January 1, 2017 to December 31, 2017, but is now the twelve months immediately subsequent to the separation of the generation assets from DP&L.

As of June 30, 2017, DP&L was in compliance with all debt covenants, including the financial covenants described above.

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The cost of borrowing under DP&L's unsecured revolving credit agreement and Bond Purchase and Covenants Agreement adjusts under certain credit rating scenarios.

Substantially all property, plant & equipment of DP&L is subject to the lien of the mortgage securing DP&L’s First and Refunding Mortgage. In July 2017, assets related to the Miami Fort station and the Zimmer station were released from the lien of DP&L's First and Refunding Mortgage in connection with the pending sale. See Note 13 – Assets and Liabilities Held For Sale for additional information.

Note 8 – Income Taxes

The following table details the effective tax rates for the three and six months ended June 30, 2017 and 2016.

	Three months ended		Six months ended
	June 30,		June 30,
	2017	2016	2017	2016
DP&L	38.8%	36.4%	31.3%	36.9%

Income tax expense for the three and six months ended June 30, 2017 and 2016 was calculated using the estimated annual effective income tax rates for 2017 and 2016 of 30.4% and 36.7%, 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 rates estimated could be materially different from the actual effective tax rates. To the extent that actual pre-tax results for the year differ from the forecasts applied to the most recent interim period, the rates estimated could be materially different from the actual effective tax rates.

The decrease in the annual effective rate compared to the same period in 2016 is primarily due to the forecasted tax expense relating to flow-through depreciation and the projected manufacturer's production deduction.

Income taxes paid, net, were $26.2 million and $0.1 million for the six months ended June 30, 2017 and 2016, respectively. For the six months ended June 30, 2017, the $26.2 million represented payments made to DPL.

Note 9 – Benefit Plans

DP&L sponsors a defined benefit pension plan for the vast 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 $5.0 million in employer contributions during each of the six months ended June 30, 2017 and 2016.

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 but are still participants in the DP&L plan.

The net periodic benefit cost of the pension benefit plans for the three and six months ended June 30, 2017 and 2016 was:

Net Periodic Benefit Cost	Pension
	Three months ended						Six months ended
	June 30,						June 30,
$ in millions	2017			2016			2017			2016
Service cost	$	1.4		$	1.4		$	2.8		$	2.8
Interest cost	3.5			3.7			7.1			7.4
Expected return on plan assets	(5.7		)	(5.7		)	(11.4		)	(11.4		)
Plan curtailment (a)	—			—			5.6			—
Amortization of unrecognized:
Prior service cost	0.3			0.7			0.8			1.5
Actuarial loss	2.3			1.8			4.5			3.6
Net periodic benefit cost	$	1.8		$	1.9		$	9.4		$	3.9

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(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. See Note 14 – 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 $15.7 million at June 30, 2017 and $15.8 million at December 31, 2016 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 to be paid during	Pension
2017	$	12.5
2018	25.5
2019	26.0
2020	26.4
2021	26.7
2022 - 2026	139.6

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 June 30, 2017. All common shares are held by DP&L’s parent, DPL.

As part of the PUCO’s approval of the Merger, DP&L agreed to maintain a capital structure that includes an equity ratio, calculated as total equity divided by total capitalization, of at least 50 percent and to not have a negative retained earnings balance. After the fixed-asset impairments recorded in 2017 and 2016 and as of June 30, 2017, DP&L's equity ratio was 31% 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.

During the six months ended June 30,2017, DP&L paid $9.0 million in cash to DPL, which was treated as a return of capital reducing Other paid-in capital.

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. If OVEC defaulted on its debt payments, DP&L could be responsible for repayment of its share of OVEC's debt. As of June 30, 2017, this amount was 4.9%, or $71.8 million, of a $1,465.4 million debt obligation that has 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 June 30, 2017, 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, 2016.

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 in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims, tax examinations and other matters discussed below, and to comply with applicable laws and

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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 June 30, 2017, cannot be reasonably determined.

Environmental Matters

DP&L’s facilities and operations are subject to a wide range of federal, state and local environmental regulations and laws. The environmental issues that may affect us include:

• The federal CAA and state laws and regulations (including 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. DP&L has installed emission control technology and is taking other measures to comply with required and anticipated reductions;

• Rules and future rules issued by the USEPA, 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.

Note 12 – Business Segments

DP&L currently manages the business through two reportable operating segments, the T&D segment and the Generation segment. The primary segment performance measure is income / (loss) from operations before income tax as management has concluded that income / (loss) from operations before income tax best reflects the underlying business performance of DP&L and is the most relevant measure considered in DP&L’s internal evaluation of the financial performance of its segments. The segments are discussed further below:

Transmission and Distribution Segment

The T&D segment is comprised primarily of DP&L’s electric transmission and distribution businesses, which distribute electricity to residential, commercial, industrial and governmental customers. DP&L distributes electricity to more than 520,000 retail customers who are located in a 6,000 square mile area of West Central Ohio. DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates, and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs. The T&D segment includes revenues and costs associated with our investment in OVEC and the historical results of DP&L’s Beckjord, Hutchings Coal, and East Bend generating facilities, which were either closed or sold in prior periods. As these assets will not be transferring to AES Ohio Generation when DP&L’s planned generation separation occurs, they are grouped with the T&D assets for segment reporting purposes. In addition, regulatory deferrals and collections, which include fuel deferrals in historical periods, are included in the T&D segment.

Generation Segment

The Generation segment is comprised of DP&L’s electric generation business. Beginning in 2001, Ohio law gave consumers the right to choose the electric generation supplier from whom they purchase retail generation services. DP&L's Generation segmentowns multiple coal-fired and peaking electric generating facilities. DP&L's Generation segment sells its generated energy and capacity into the wholesale market as DP&L sources all of the generation for its SSO customers through a competitive bid process.

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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 cost of sales are eliminated in consolidation. Certain shared and corporate costs are allocated among reporting segments.

The following tables present financial information for each of DP&L’s reportable business segments:

$ in millions	T&D		Generation		Adjustments and Eliminations		DP&L Total
Three months ended June 30, 2017
Revenues from external customers	$	168.2	$	115.9	$	—	$	284.1
Intersegment revenues	—		—		—		—
Total revenues	$	168.2	$	115.9	$	—	$	284.1
Depreciation and amortization	$	18.6	$	3.4	$	—	$	22.0
Interest expense	$	7.8	$	—	$	—	$	7.8
Income from operations before income tax	$	15.1	$	11.2	$	—	$	26.3
Cash capital expenditures	$	19.4	$	4.1	$	—	$	23.5

$ in millions	T&D		Generation			Adjustments and Eliminations		DP&L Total
Three months ended June 30, 2016
Revenues from external customers	$	185.1	$	128.6		$	—	$	313.7
Intersegment revenues	—		—			—		—
Total revenues	$	185.1	$	128.6		$	—	$	313.7
Depreciation and amortization	$	17.6	$	19.2		$	—	$	36.8
Fixed-asset Impairments (Note 14)	$	—	$	857.1		$	—	$	857.1
Interest expense	$	5.3	$	0.1		$	—	$	5.4
Income / (loss) from operations before income tax	$	30.1	$	(865.4	)	$	—	$	(835.3	)
Cash capital expenditures	$	18.1	$	17.9		$	—	$	36.0

$ in millions	T&D		Generation			Adjustments and Eliminations		DP&L Total
Six months ended June 30, 2017
Revenues from external customers	$	358.3	$	236.9		$	—	$	595.2
Intersegment revenues	—		—			—		—
Total revenues	$	358.3	$	236.9		$	—	$	595.2
Depreciation and amortization	$	36.7	$	8.8		$	—	$	45.5
Fixed-asset Impairments (Note 14)	$	—	$	66.3		$	—	$	66.3
Interest expense	$	15.2	$	0.2		$	—	$	15.4
Income / (loss) from operations before income tax	$	40.1	$	(77.5	)	$	—	$	(37.4	)
Cash capital expenditures	$	45.7	$	11.9		$	—	$	57.6
At June 30, 2017
Total assets	$	1,647.5	$	201.1		$	—	$	1,848.6

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$ in millions	T&D		Generation			Adjustments and Eliminations		DP&L Total
Six months ended June 30, 2016
Revenues from external customers	$	389.6	$	273.3		$	—	$	662.9
Intersegment revenues	—		—			—		—
Total revenues	$	389.6	$	273.3		$	—	$	662.9
Depreciation and amortization	$	34.8	$	36.3		$	—	$	71.1
Fixed-asset Impairments (Note 14)	$	—	$	857.1		$	—	$	857.1
Interest expense	$	10.5	$	0.2		$	—	$	10.7
Income / (loss) from operations before income tax	$	64.5	$	(853.7	)	$	—	$	(789.2	)
Cash capital expenditures	$	42.2	$	29.6		$	—	$	71.8
At December 31, 2016
Total assets	$	1,710.5	$	324.6		$	—	$	2,035.1

Note 13 – Assets and Liabilities Held For Sale

On April 21, 2017, DP&L and AES Ohio Generation entered into an Asset Purchase Agreement with subsidiaries of Dynegy Inc., for the sale of DP&L's undivided interests in the Zimmer Station and the Miami Fort Station for cash and the assumption of certain liabilities, including environmental liabilities. The cash purchase price is subject to adjustment at closing based on the amount of certain inventories, pre-paid amounts, employment benefits, insurance premiums, property taxes and other costs prior to closing. The sale is subject to approval by the FERC and is expected to close in the third quarter of 2017.

Accordingly, the assets and liabilities of Zimmer Station and Miami Fort Station were classified as held for sale as of June 30, 2017, but the plants did not meet the criteria to be reported as discontinued operations. The following table summarizes the major classes of assets and liabilities as of June 30, 2017:

$ in millions	June 30, 2017
Assets
Inventories	$	24.0
Property, plant & equipment, net	44.6
Total assets of the disposal group classified as held for sale in the balance sheet	$	68.6
Liabilities
Accounts payable	$	12.9
Accrued taxes	4.9
Asset retirement obligations	3.7
Other liabilities	0.7
Total liabilities of the disposal group classified as held for sale in the balance sheet	$	22.2

Zimmer Station and Miami Fort Station's results are reflected within continuing operations in the Condensed Statements of Operations. The combined income / (loss) from continuing operations before income tax for Zimmer Station and Miami Fort Station was $3.0 million and $(9.7) million for the three months ended June 30, 2017 and 2016, respectively, and $2.2 million and $(16.2) million for the six months ended June 30, 2017 and 2016, respectively. Zimmer Station and Miami Fort Station are included in the Generation segment.

Note 14 – Fixed-asset Impairments

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. 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

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cash flows under the income approach. As a result, we recognized asset impairment expense of $39.0 million and $27.3 million for Stuart Station and Killen Station, respectively.

Additionally, as a result of the decision to retire the Facilities by June 1, 2018, we concluded that inventory at these Facilities is considered obsolete. As a result, we recognized a loss on disposal of $9.8 million and $6.4 million for Stuart Station and Killen Station inventories, respectively, during the first quarter of 2017, which is recorded in Loss on asset disposal in the Condensed Statements of Operations.

During the second quarter of 2016, we tested the recoverability of our long-lived assets at certain of our generation facilities at DP&L. A ruling by the Supreme Court of Ohio on June 20, 2016, lower expectation of future capacity revenue resulting from the most recent PJM capacity auction and a higher anticipated level of environmental compliance costs resulting from third party studies were collectively determined to be an impairment indicator for these assets. We performed a long-lived asset impairment analysis and determined that the carrying amount of the asset groups of Stuart, Killen and Zimmer were not recoverable. The asset groups of Stuart, Killen and Zimmer were determined to have fair values of $164.4 million, $84.3 million and $111.0 million, respectively, using the discounted cash flows under the income approach. As a result, we recognized asset impairment expense of $292.0 million, $246.2 million and $318.9 million for Stuart, Killen and Zimmer, respectively.

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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.

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, 2016 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.

Key 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

▪ DP&L - T&D Segment

▪ DP&L - Generation Segment

• Key Trends and Uncertainties

• Capital Resources and Liquidity

• Critical Accounting Estimates

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. See Note 10 – Contractual Obligations, Commercial Commitments and Contingencies of Notes to DPL’s Condensed Consolidated Financial Statements and Note 11 – Contractual Obligations, Commercial Commitments and Contingencies of Notes to DP&L’s Condensed Financial Statements. In addition to matters discussed or updated herein, our Forms 10-K and 10-Q previously filed with the SEC during 2017 describe other regulatory matters which have not materially changed since those filings.

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 June 30, 2017. 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 2016 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.

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As a result of DP&L’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 DP&L 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.

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. As discussed in our Form 10-K, the CP program, which was previously approved by the FERC, will phase out RPM as of the 2018/19 period. We cannot predict the outcome of future auctions but based on actual results attained, we estimate that a hypothetical increase or decrease of $10/MW-day in the capacity auction price would result in an annual impact to net income of approximately $5.4 million and $4.6 million for DPL and DP&L, respectively. These estimates do not, however, take into consideration the other factors that may affect the impact of capacity revenues and costs on net income such as our generation capacity and the levels of wholesale revenues. These estimates are discussed further within Commodity Pricing Risk under the Market Risk section of this Management Discussion & Analysis.

OHIO COMPETITION AND REGULATORY PROCEEDINGS

Since January 2001, DP&L’s electric customers have been permitted to choose their retail electric generation supplier. DP&L continues to have the exclusive right to provide delivery service in its state certified territory and the obligation to provide retail generation service to customers that do not choose an alternative supplier; however, the supply of electricity for DP&L’s SSO customers is all sourced through competitive bid as of January 2016. The PUCO maintains jurisdiction over DP&L’s delivery of electricity, SSO and other retail electric services.

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 $65.0 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 have an effect of approximately 4% on a typical residential customer bill based on rates in effect at the time of the filing.

Ohio law requires that all Ohio distribution utilities file either an ESP or MRO to establish rates for SSO service. For a discussion of the current status of DP&L's ESPs, please see 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.

Ohio law and PUCO rules contain targets relating to renewable energy, peak demand reduction and energy efficiency standards. If any targets are not met, compliance penalties will apply unless the PUCO makes certain findings that would excuse performance. DP&L is in full compliance with energy efficiency, peak demand reduction and renewable targets. In 2016, DP&L filed a new energy efficiency portfolio plan for the years 2017 through 2019. Ultimately, DP&L entered into a settlement agreement (which is subject to PUCO approval), under which it has agreed to an extension of its current plan with slight changes through 2017. Consistent with that agreement, on June 15, 2017, DP&L filed a new energy efficiency portfolio plan for programs in years 2018 through 2020.

DP&L and AES Ohio Generation have filed an application before the FERC to adjust their rates with respect to reactive power provided to PJM from their generation units. On March 3, 2017, DP&L, AES Ohio Generation, and certain intervening parties filed an Offer of Settlement that was approved by the FERC on May 16, 2017. The changes from current reactive power rates are not material. Additionally, the FERC has referred to FERC’s Office of Enforcement for investigation of an issue regarding reactive power charges under the previously effective rates in light of changes in DP&L’s generation portfolio. DP&L's reactive power rates were last reset in 1998. As of the date of this report, DP&L is unable to predict the ultimate outcome of the investigation. Several other utilities within

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PJM are also being investigated by FERC’s Office of Enforcement on the same issue of changes in the generation portfolio that occurred in between rate proceedings.

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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 June 30,						Six months ended June 30,
$ in millions	2017			2016			2017			2016
Revenues:
Retail	$	151.4		$	168.5		$	323.3		$	355.7
Wholesale	94.5			107.3			197.6			229.7
RTO revenues	14.4			14.8			28.4			30.4
RTO capacity revenues	34.7			35.2			66.8			71.7
Other revenues	3.1			2.5			5.9			4.8
Total revenues	298.1			328.3			622.0			692.3
Cost of revenues:
Fuel costs	54.3			61.9			108.7			130.5
Gains from the sale of coal	(0.3		)	(1.3		)	(0.6		)	(3.0		)
Mark-to-market gains	—			(0.4		)	—			(0.4		)
Total fuel	54.0			60.2			108.1			127.1
Purchased power	59.8			77.2			137.2			168.4
RTO charges	16.4			16.2			37.5			37.0
RTO capacity charges	3.7			6.5			6.9			14.9
Mark-to-market gains	(2.5		)	(3.0		)	(2.2		)	(1.5		)
Total purchased power	77.4			96.9			179.4			218.8
Total cost of revenues	131.4			157.1			287.5			345.9
Gross margin	166.7			171.2			334.5			346.4
Operating expenses:
Operation and maintenance	82.1			77.2			168.4			165.7
Depreciation and amortization	26.5			36.0			54.5			69.4
General taxes	24.0			21.6			48.2			42.6
Fixed-asset impairment	—			235.5			66.4			235.5
Loss / (gain) on asset disposal	(3.2		)	—			16.2			0.1
Other	0.3			—			(0.9		)	—
Total operating expenses	129.7			370.3			352.8			513.3
Operating income / (loss)	37.0			(199.1		)	(18.3		)	(166.9		)
Other income / (expense), net:
Investment income	0.1			0.3			0.1			0.2
Interest expense	(27.4		)	(26.0		)	(54.3		)	(52.3		)
Charge for early redemption of debt	(0.3		)	—			(0.3		)	(2.6		)
Other deductions	(0.6		)	(0.3		)	(1.6		)	(0.7		)
Total other expense, net	(28.2		)	(26.0		)	(56.1		)	(55.4		)
Income / (loss) from continuing operations before income tax (a)	$	8.8		$	(225.1	)	$	(74.4	)	$	(222.3	)

(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 June 30,		Six months ended June 30,
	2017	2016	2017	2016
Heating degree days (a)	393	605	2,685	3,181
Cooling degree days (a)	276	301	278	301

(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 difference of the average actual daily temperature 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. In a similar manner, cooling degrees in a day are the difference of the average actual daily temperature in excess of 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; 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			Six months ended
	June 30,			June 30,
$ in millions	2017 vs. 2016			2017 vs. 2016
Retail
Rate	$	(13.9	)	$	(18.2	)
Volume	(4.2		)	(18.6		)
Other miscellaneous	1.0			4.4
Total retail change	(17.1		)	(32.4		)
Wholesale
Rate	(5.4		)	(16.8		)
Volume	(7.4		)	(15.3		)
Total wholesale change	(12.8		)	(32.1		)
RTO revenues and RTO capacity revenues
RTO revenues and RTO capacity revenues	(0.9		)	(6.9		)
Other
Other revenues	0.6			1.1
Total revenues change	$	(30.2	)	$	(70.3	)

During the three months ended June 30, 2017, Revenues decreased $30.2 million to $298.1 million from $328.3 million in the same period of the prior year. This decrease was primarily the result of lower average retail and wholesale rates, lower retail and wholesale volumes, and lower RTO revenues and RTO capacity revenues. The changes in the components of revenue are discussed below:

• Retail revenues decreased $17.1 million primarily due to lower average DP&L retail rates and lower DP&L retail volumes. The decrease in average retail rates was primarily driven by reverting to ESP 1 rates in September of 2016 and a decrease in the USF revenue rate rider, partially offset by increased revenue associated with energy efficiency programs recorded in 2017. The decrease in retail volume was primarily

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driven by more mild weather in 2017, as heating degree days decreased by 212 degree days and cooling degree days decreased by 25 degree days. The aforementioned impacts resulted in an unfavorable $13.9 million retail price variance and an unfavorable $4.2 million retail volume variance. These variances were partially offset by a favorable other miscellaneous variance of $1.0 million.

• Wholesale revenues decreased $12.8 million primarily as a result of an unfavorable $7.4 million wholesale volume variance and an unfavorable $5.4 million wholesale price variance. Despite increases in PJM market prices, the unfavorable price variance was due to lower realized gains on derivatives in 2017. The decrease in wholesale volumes of $7.4 million was primarily driven by a decrease in the load served of other parties through their competitive bid process, as well as a 4% decrease in internal generation at DPL's plants in 2017.

• 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 $0.9 million compared to the same period in the prior year. This decrease was the result of a $0.5 million decrease in revenue realized from the PJM capacity auction in 2017 due to lower average prices in the CP and RPM auctions as well as less capacity cleared. 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, and $136/MW-day in June of 2015. There was also a $0.4 million decrease in RTO revenues due to lower rates related to compensation for DPL's reactive supply and operating reserves.

During the six months ended June 30,2017, Revenues decreased $70.3 million to $622.0 million from $692.3 million in the same period of the prior year. This decrease was primarily the result of lower average retail and wholesale rates, lower retail and wholesale volumes, and lower RTO revenues and RTO capacity revenues. The changes in the components of revenue are discussed below:

• Retail revenues decreased $32.4 millionprimarily due to lower average DP&L retail rates and lower DP&L retail volumes. The decrease in average retail rates was primarily driven by reverting to ESP 1 rates in September of 2016, collections on the remaining 2015 deferred fuel balance in the first quarter of 2016, and a decrease in the USF revenue rate rider, partially offset by increased revenue associated with energy efficiency programs recorded in 2017. The decrease in retail volume was primarily driven by more mild weather in 2017, as heating degree days decreased by 496 degree days and cooling degree days decreased by 23 degree days. The aforementioned impacts resulted in an unfavorable $18.6 million retail volume variance and an unfavorable $18.2 million retail price variance. These variances were partially offset by a favorable other miscellaneous variance of $4.4 million.

• Wholesale revenues decreased $32.1 million primarily as a result of an unfavorable $16.8 million wholesale price variance and an unfavorable $15.3 million wholesale volume variance. Despite increases in PJM market prices, the unfavorable price variance was due to lower realized gains on derivatives in 2017. The decrease in wholesale volumes of $15.3 million was primarily driven by a decrease in the load served of other parties through their competitive bid process and a 3% decrease in internal generation at DPL's plants in 2017.

• 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 $6.9 million compared to the same period in the prior year. This decrease was the result of a $4.9 million decrease in revenue realized from the PJM capacity auction in 2017 primarily due to lower average prices in the CP and RPM auctions as well as less capacity cleared year over year. 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, and $136/MW-day in June of 2015. There was also a $2.0 million decrease in RTO revenues due to lower rates related to compensation for DPL's reactive supply and operating reserves.

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DPL – Cost of Revenues

During the three months ended June 30, 2017, Cost of revenues decreased $25.7 million compared to the same period in the prior year:

• Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $6.2 million compared to the same period in the prior year primarily due to a 9% decrease in average fuel cost per MWh and a 4% decrease in internal generation.

• Net purchased power decreased $19.5 million compared to the same period in the prior year. This change was driven by the following factors:

◦ Purchased power decreased $17.4 million primarily due to a $10.5 million volume decrease and a $6.9 million price decrease compared to the same period in the prior year. The volume decrease was primarily driven by a lower load served through the competitive bid process of other parties compared to 2016, as well as the decrease in DP&L retail demand in 2017. The price decrease was primarily driven by lower rates in the competitive bid process in 2017 than 2016.

◦ RTO charges increased $0.2 million compared to the same period in the prior year. 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 TCRR-N rider, transmission and congestion losses incurred on DP&L's wholesale revenues, and costs associated with load obligations for retail customers.

◦ RTO capacity charges decreased $2.8 million compared to the same period in the prior year primarily due to a lower retail load served in 2017. Retail load served relates to the load of other parties through their competitive bid process. As noted in the Revenues section above, RTO capacity prices are set by an annual auction.

◦ Mark-to-market gainsdecreased $0.5 million due to changes in power prices in 2017 and 2016.

During the six months ended June 30,2017, Cost of revenues decreased $58.4 million compared to the same period in the prior year:

• Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $19.0 million compared to the same period in the prior year primarily due to a 14% decrease in average fuel cost per MWh and a 3% decrease in internal generation. There were fuel costs deferred in 2015, which were expensed in 2016 because they were collected in 2016, which contributed to the price decrease. There were no fuel costs deferred or collected in the first six months of 2017.

• Net purchased power decreased $39.4 million compared to the same period in the prior year. This decrease was driven by the following factors:

◦ Purchased power decreased $31.2 million primarily due to a $24.5 million volume decrease and a $6.7 million price decrease compared to the same period in the prior year. The volume decrease was primarily driven by a lower load served through the competitive bid process of other parties compared to 2016, as well as the decrease in DP&L retail demand in 2017. The price decrease was primarily driven by lower rates in the competitive bid process in 2017 than 2016.

◦ RTO charges increased $0.5 million compared to the same period in the prior year. 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 TCRR-N rider, transmission and congestion losses incurred on DP&L's wholesale revenues, and costs associated with load obligations for retail customers.

◦ RTO capacity charges decreased $8.0 million compared to the same period in the prior year primarily due to a lower retail load served in 2017, as well as a $1.7 million PJM penalty incurred in March 2016 associated with low plant availability. Retail load served relates to the load of other parties through their competitive bid process. As noted in the Revenues section above, RTO capacity prices are set by an annual auction.

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◦ Mark-to-market gainsincreased $0.7 million due to changes in power prices in 2017 and 2016.

DPL – Operation and Maintenance

During the three and six months ended June 30, 2017, Operation and Maintenance expense increased $4.9 million and $2.7 million, respectively, compared to the same periods in the prior year. The main drivers of these changes are as follows:

	Three months ended			Six months ended
	June 30,			June 30,
$ in millions	2017 vs. 2016			2017 vs. 2016
Increase in group insurance expense	$	6.5		$	7.3
Increase in retirement benefits costs, primarily due to pension curtailment charges associated with announced plant closures	0.7			5.4
Increase / (decrease) in generating facilities operating and maintenance expenses	(0.4		)	3.1
Decrease in uncollectible expenses for the low-income payment program, which is funded by the USF revenue rate rider (a)	(5.0		)	(12.0		)
Other, net	3.1			(1.1		)
Net change in operation and maintenance expense	$	4.9		$	2.7

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

DPL – Depreciation and Amortization

During the three and six months ended June 30, 2017, Depreciation and amortization decreased $9.5 million and $14.9 million respectively, compared to the same periods in the prior year. The decrease was primarily a result of the fixed-asset impairments in the second and fourth quarters of 2016, and the first quarter of 2017, which reduced depreciation expense due to the lower asset values. In addition, the decrease was attributable to the discontinuation of Miami Fort and Zimmer depreciation expense due to the pending sale of these two plants.

DPL – General Taxes

During the three months ended June 30, 2017, General taxes increased $2.4 million compared to the same period in the prior year. The increase was primarily the result of a $1.2 million true-up of the 2016 Ohio property tax accrual to reflect actual payments made in 2017, and a $0.4 million increase in the 2017 accrual to reflect a higher estimated 2017 liability.

During the six months ended June 30,2017, General taxes increased $5.6 million compared to the same period in the prior year. The increase was primarily the result of lower expense in 2016 due to a $1.6 million favorable true-up of the 2015 Ohio property tax accrual to reflect actual payments made in 2016. In addition, 2017 expense was higher due to a $1.6 million unfavorable true-up of the 2016 and 2017 Ohio property tax accruals to reflect actual payments made in 2017 and higher rates.

DPL – Fixed-asset Impairment

During the six months ended June 30,2017, 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 14 – Fixed-asset Impairments of Notes to DPL's Condensed Consolidated Financial Statements.

During the three and six months ended June 30, 2016, DPL recorded an impairment of fixed assets of $235.5 million. For more information, see Note 14 – Fixed-asset Impairments of Notes to DPL's Condensed Consolidated Financial Statements.

DPL – Loss (Gain) on Asset Disposal

During the three months ended June 30, 2017, DPL recorded a gain on asset disposal of $3.2 million to offset the net loss recorded on the disposal of assets in the first quarter of 2017 related to the high pressure feedwater heater shell failure on Unit 1 at Stuart station, due to additional accrued insurance recoveries.

During the six months ended June 30,2017, DPL recorded a loss on asset disposal of $16.2 million related to the write-off of plant materials and supplies inventory at the Stuart and Killen plants. There was also a $6.4 million loss

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recorded on the disposal of assets related to the high pressure feedwater heater shell failure on Unit 1 at Stuart station; however, this was completely offset by accrued insurance proceeds.

DPL – Charge for Early Redemption of Debt

During the six months ended June 30,2017, Charge for early redemption of debt decreased $2.3 million primarily due to the February 2016 make-whole premium of $2.4 million associated with the early redemption of $73.0 million of the 6.5% Senior Notes due in 2016.

DPL – Income Tax Expense

During the three months ended June 30, 2017, Income tax expense / (benefit) increased $96.6 million compared to the same period in the prior year primarily due to pre-tax income in the current year versus a pre-tax loss in the prior year.

During the six months ended June 30,2017, Income tax benefit decreased $64.5 million compared to the same period in the prior year primarily due to a significantly lower pre-tax loss in the current year versus the prior year.

RESULTS OF OPERATIONS BY SEGMENT – DPL Inc.

DPL currently manages the 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 520,000 retail customers who are located in a 6,000 square mile area of West Central Ohio. DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates, and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs. The T&D segment includes revenues and costs associated with our investment in OVEC and the historical results of DP&L’s Beckjord, Hutchings Coal, and East Bend generating facilities, which were either closed or sold in prior periods. As these assets will not be transferring to AES Ohio Generation when DP&L’s planned generation separation occurs, they are grouped with the T&D assets for segment reporting purposes. In addition, regulatory deferrals and collections, which include fuel deferrals in historical periods, are included in the T&D segment.

Generation Segment

The Generation segment is comprised of AES Ohio Generation and DP&L’s electric generation business. Beginning in 2001, Ohio law gave consumers the right to choose the electric generation supplier from whom they purchase retail generation services. AES Ohio Generation owns and operates peaking generating facilities, and DP&L owns multiple coal-fired and peaking electric generating facilities. Both AES Ohio Generation and DP&L primarily sell their generated energy and capacity into the PJM wholesale market as DP&L sources all of the generation for its SSO customers through a competitive bid process.

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 11 – 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 June 30,						Six months ended June 30,
$ in millions	2017			2016			2017			2016
T&D	$	15.1		$	29.8		$	40.1		$	64.0
Generation	13.2			(861.6		)	(73.6		)	(873.9		)
Other	(19.5		)	606.7			(40.9		)	587.6
Income / (loss) from continuing operations before income tax (a)	$	8.8		$	(225.1	)	$	(74.4	)	$	(222.3	)

(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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Statement of Operations Highlights – DPL Inc. – T&D Segment

	Three months ended June 30,						Six months ended June 30,
$ in millions	2017			2016			2017			2016
Revenues:
Retail	$	151.6		$	168.8		$	323.8		$	356.3
Wholesale	3.5			3.4			8.6			7.0
RTO revenues	11.5			11.4			23.0			22.7
RTO capacity revenues	1.6			1.5			2.9			3.6
Total revenues	168.2			185.1			358.3			389.6
Cost of revenues:
Net fuel cost	—			—			—			5.3
Purchased power:
Purchased power	53.3			60.1			120.0			126.0
RTO charges	13.1			13.6			27.5			28.6
RTO capacity charges	0.1			0.3			0.1			(0.4		)
Total purchased power	66.5			74.0			147.6			154.2
Total cost of revenues	66.5			74.0			147.6			159.5
Gross margin	101.7			111.1			210.7			230.1
Operating expenses:
Operation and maintenance	40.2			41.3			79.0			87.6
Depreciation and amortization	18.6			17.6			36.7			34.8
General taxes	19.6			17.4			38.5			33.0
Loss on asset disposal	—			(0.5		)	—			(0.4		)
Total operating expenses	78.4			75.8			154.2			155.0
Operating income	23.3			35.3			56.5			75.1
Other expense, net
Investment income	0.1			0.2			0.1			0.2
Interest expense	(7.8		)	(5.6		)	(15.2		)	(11.0		)
Charge for early retirement of debt	(0.1		)	—			(0.1		)	—
Other expense	(0.4		)	(0.1		)	(1.2		)	(0.3		)
Total other expense, net	(8.2		)	(5.5		)	(16.4		)	(11.1		)
Income from continuing operations before income tax (a)	$	15.1		$	29.8		$	40.1		$	64.0

(a) For purposes of discussing operating results, we present and discuss Income 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 Inc. –T&D Segment – Revenues

During the three months ended June 30, 2017, the segment’s revenues decreased $16.9 million to $168.2 million from $185.1 million in the same period of the prior year. This decrease was primarily the result of lower retail volumes and lower average retail rates.

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• Retail revenues decreased $17.2 million primarily due to lower average DP&L retail rates and lower DP&L retail volumes. The decrease in average retail rates was primarily driven by reverting to ESP 1 rates in September of 2016 and a decrease in the USF revenue rate rider, partially offset by increased revenue associated with energy efficiency programs recorded in 2017. The decrease in retail volume was primarily driven by more mild weather in 2017, as heating degree days decreased by 212 degree days and cooling degree days decreased by 25 degree days. The aforementioned impacts resulted in an unfavorable $4.3 million retail volume variance and an unfavorable $13.9 million retail price variance. These variances were partially offset by a favorable other miscellaneous variance of $1.0 million.

• Wholesale revenues increased $0.1 million. These revenues, included in the T&D segment, consist of our 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.

During the six months ended June 30,2017, the segment’s revenues decreased $31.3 million to $358.3 million from $389.6 million in the same period of the prior year. This decrease was primarily the result of lower retail volumes and lower average retail rates, partially offset by higher wholesale revenues.

• Retail revenues decreased $32.5 millionprimarily due to lower average DP&L retail rates and lower DP&L retail volumes. The decrease in average retail rates was primarily driven by reverting to ESP 1 rates in September of 2016, collections on the remaining 2015 deferred fuel balance in the first quarter of 2016, and a decrease in the USF revenue rate rider, partially offset by increased revenue associated with energy efficiency programs recorded in 2017. The decrease in retail volume was primarily driven by more mild weather in 2017, as heating degree days decreased by 496 degree days and cooling degree days decreased by 23 degree days. The aforementioned impacts resulted in an unfavorable $18.7 million retail volume variance and an unfavorable $18.3 million retail price variance. In addition, there was a favorable other miscellaneous variance of $4.5 million.

• Wholesale revenues increased $1.6 million. These revenues, included in the T&D segment, consist of our 4.9% share of the generation output of OVEC, which is sold into PJM at market prices. As such, the increase in wholesale revenue is due to increased OVEC revenue.

• RTO capacity and other revenues decreased $0.4 million compared to the same period in the prior year.

DPL Inc. –T&D Segment – Cost of Revenues

During the three months ended June 30, 2017, Total cost of revenues decreased $7.5 million compared to the prior year. This decrease was a result of:

• Net purchased power decreased $7.5 million compared to the prior year. This was driven by the following factors:

◦ Purchased power decreased $6.8 million compared to the same period in the prior year primarily due to a favorable price variance of $3.4 million driven by lower rates in the competitive bid process in 2017, and lower volumes of $3.4 million due to the decrease in DP&L retail demand in 2017.

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

During the six months ended June 30,2017, Total cost of revenues decreased $11.9 million compared to the prior year. This decrease was a result of:

• Net fuel costs, which include expense recognition or deferral coinciding with the collection of fuel costs through the regulatory fuel deferral, decreased $5.3 million compared to the prior year primarily due to fuel costs deferred in 2015, being collected in 2016. There were no fuel costs deferred or collected in the first quarter of 2017.

• Net purchased power decreased $6.6 million compared to the prior year. This was driven by the following factors:

◦ Purchased power decreased $6.0 million compared to the same period in the prior year primarily due to a favorable price variance of $1.0 million driven by lower rates in the competitive bid process in 2017, and lower volumes of $5.0 million due to the decrease in DP&L retail demand in 2017.

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

DPL Inc. –T&D Segment – Operating Expenses

During the three and six months ended June 30, 2017, Operating expenses increased $2.6 million and decreased $0.8 million, respectively, compared to the same periods in the prior year. The main drivers of these changes are as follows:

	Three months ended June 30,			Six months ended June 30,
$ in millions	2017 vs. 2016			2017 vs. 2016
Decrease in uncollectible expenses for the low-income payment program, which is funded by the USF revenue rate rider (a)	$	(5.0	)	$	(12.0	)
Increase in General taxes (b)	2.2			5.5
Increase in group insurance expense	3.4			3.4
Increase in Depreciation and amortization expense primarily due to additional investments in T&D fixed assets	1.0			1.9
Other, net	1.0			0.4
Net change in operating expenses	$	2.6		$	(0.8	)

(a) There is a corresponding offset in Revenues associated with these programs, resulting in no impact to Income from continuing operations before income tax.

(b) During the three months ended June 30, 2017, General taxes increased $2.2 million compared to the same period in the prior year. The increase was primarily the result of a $1.2 million true-up of the 2016 Ohio property tax accrual to reflect actual payments made in 2017, and a $0.4 million increase in the 2017 accrual to reflect a higher estimated 2017 liability. During the six months ended June 30,2017, General taxes increased $5.5 million compared to the same period in the prior year. The increase was primarily the result of lower expense in 2016 due to a $1.6 million favorable true-up of the 2015 Ohio property tax accrual to reflect actual payments made in 2016. In addition, 2017 expense was higher due to a $1.6 million unfavorable true-up of the 2016 and 2017 Ohio property tax accruals to reflect actual payments made in 2017 and higher rates.

DPL Inc. –T&D Segment – Interest Expense

During the three months ended June 30, 2017, Interest expense increased $2.2 million compared to the same period in the prior year primarily driven by higher interest rates on the $445.0 million variable rate Term Loan B maturing on August 24, 2022 compared to the interest rate on the 1.875% First Mortgage Bonds Due 2016.

During the six months ended June 30,2017, Interest expense increased $4.2 million compared to the same period in the prior year primarily driven by higher interest rates on the $445.0 million variable rate Term Loan B maturing on August 24, 2022 compared to the interest rate on the 1.875% First Mortgage Bonds Due 2016.

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Statement of Operations Highlights–DPL Inc. – Generation Segment

	Three months ended June 30,						Six months ended June 30,
$ in millions	2017			2016			2017			2016
Revenues:
Retail	$	0.1		$	0.1		$	0.1		$	0.1
Wholesale	91.3			104.3			189.8			223.7
RTO revenues	2.9			3.4			5.4			7.7
RTO capacity revenues	33.1			33.7			63.9			68.1
Other mark-to-market losses	—			(0.1		)	—			—
Total revenues	127.4			141.4			259.2			299.6
Cost of revenues:
Cost of fuel:
Fuel costs	54.3			61.9			108.7			124.9
Gains from the sale of coal	(0.3		)	(1.3		)	(0.6		)	(2.7		)
Mark-to-market gains	—			(0.4		)	—			(0.4		)
Net fuel costs	54.0			60.2			108.1			121.8
Purchased power:
Purchased power	6.5			17.5			17.2			43.4
RTO charges	3.3			2.6			10.0			8.4
RTO capacity charges	3.6			6.2			6.8			15.3
Mark-to-market gains	(2.5		)	(3.1		)	(2.2		)	(1.5		)
Net purchased power	10.9			23.2			31.8			65.6
Total cost of revenues	64.9			83.4			139.9			187.4
Gross margin	62.5			58.0			119.3			112.2
Operating expenses:
Operation and maintenance	42.8			36.9			89.7			79.3
Depreciation and amortization	4.9			20.8			11.9			39.4
General taxes	4.3			4.2			9.5			9.6
Fixed-asset impairment	—			857.1			66.3			857.1
Loss / (gain) on asset disposal	(3.2		)	0.5			16.2			0.5
Other	0.3			—			(0.9		)	—
Total operating expenses	49.1			919.5			192.7			985.9
Operating income / (loss)	13.4			(861.5		)	(73.4		)	(873.7		)
Other expense, net
Interest expense	(0.2		)	(0.1		)	(0.2		)	(0.2		)
Total other expense, net	(0.2		)	(0.1		)	(0.2		)	(0.2		)
Income / (loss) from continuing operations before income tax (a)	$	13.2		$	(861.6	)	$	(73.6	)	$	(873.9	)

(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 Inc. –Generation Segment – Revenues

During the three months ended June 30, 2017, the segment’s revenues decreased $14.0 million to $127.4 million from $141.4 million in the same period of the prior year. This decrease was primarily the result of lower wholesale volumes and lower average rates.

• Wholesale revenues decreased $13.0 million primarily as a result of an unfavorable wholesale price variance of $10.3 million and an unfavorable wholesale volume variance of $2.7 million. Despite increases in PJM market prices, the unfavorable price variance was due to lower realized gains on derivatives in 2017. The decrease in wholesale volumes was primarily driven by a decrease in the load served of other parties through their competitive bid process, as well as a 4% decrease in internal generation at DPL's plants in 2017.

• RTO capacity and other revenues, consisting primarily of PJM capacity revenues, regulation services, reactive supply and operating reserves, decreased $1.1 million compared to the same period in the prior year.

During the six months ended June 30,2017, the segment’s revenues decreased $40.4 million to $259.2 million from $299.6 million in the same period of the prior year. This decrease was primarily the result of lower wholesale volumes and rates and lower RTO capacity and other revenues.

• Wholesale revenues decreased $33.9 million primarily as a result of an unfavorable $18.9 million wholesale price variance and an unfavorable $15.0 million wholesale volume variance. Despite increases in PJM market prices, the unfavorable price variance was due to lower realized gains on derivatives in 2017. The decrease in wholesale volumes was primarily driven by a decrease in the load served of other parties through their competitive bid process and a 3% decrease in internal generation at DPL's plants in 2017.

• RTO capacity and other revenues, consisting primarily of PJM capacity revenues, regulation services, reactive supply and operating reserves, decreased $6.5 million compared to the same period in the prior year. This decrease was the result of a $4.2 million decrease in revenue realized from the PJM capacity auction in 2017 primarily due to lower average prices in the CP and RPM auctions as well as less capacity cleared year over year. 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, and $136/MW-day in June of 2015. There was also a $2.3 million decrease in RTO revenues due to lower rates related to compensation for DPL's reactive supply and operating reserves.

DPL Inc. –Generation Segment – Cost of Revenues

During the three months ended June 30, 2017, Total cost of revenues decreased $18.5 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 $6.2 million compared to the same period in the prior year primarily due to a 9% decrease in average fuel cost per MWh and a 4% decrease in internal generation.

• Net purchased power decreased $12.3 million compared to the prior year. This decrease was driven by the following factors:

◦ Purchased power decreased $11.0 million primarily due to a favorable volume variance of $9.8 million and a favorable price variance of $1.2 million. The decrease in volume was driven by a lower load served of other parties through their competitive bid process in 2016. The generation segment 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.

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

◦ RTO capacity charges decreased $2.6 million compared to the same period in the prior year primarily due to a lower retail load served in 2017. Retail load served relates to the load of other parties through their competitive bid process. As noted in the Revenues section above, RTO capacity prices are set by an annual auction.

◦ Mark-to-market gains decreased $0.6 million due to changes in power prices in 2017 and 2016.

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During the six months ended June 30,2017, Total cost of revenues decreased $47.5 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 $13.7 million compared to the same period in the prior year primarily due to a 10% decrease in average fuel cost per MWh and a 3% decrease in internal generation.

• Net purchased power decreased $33.8 million compared to the prior year. This decrease was driven by the following factors:

◦ Purchased power decreased $26.2 million primarily due to a favorable volume variance of $26.5 million, partially offset by an unfavorable price variance of $0.3 million. The decrease in volume was driven by a lower load served of other parties through their competitive bid process in 2016. The generation segment 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.

◦ RTO charges increased $1.6 million compared to the same period in the prior year.

◦ RTO capacity charges decreased $8.5 million compared to the same period in the prior year primarily due to a lower retail load served in 2017, as well as a $1.7 million PJM penalty incurred in March 2016 associated with low plant availability. Retail load served relates to the load of other parties through their competitive bid process. As noted in the Revenues section above, RTO capacity prices are set by an annual auction.

◦ Mark-to-market gains increased $0.7 million due to changes in power prices in 2017 and 2016.

DPL Inc. –Generation Segment – Operating Expenses

During the three and six months ended June 30, 2017, Operating expenses decreased $870.4 million and $793.2 million, respectively, compared to the same periods in the prior year. The main drivers of these changes are as follows:

	Three months ended June 30,			Six months ended June 30,
$ in millions	2017 vs. 2016			2017 vs. 2016
Change in Fixed-asset impairment from 2016 to 2017 (a)	(857.1		)	$	(790.8	)
Decrease in Depreciation and amortization expense as a result of the fixed-asset impairments in the second and fourth quarters of 2016 and the first quarter of 2017, which reduced depreciation expense due to the lower asset values	(15.9		)	(27.5		)
Loss / (gain) on asset disposal (b)	(3.2		)	16.2
Increase / (decrease) in retirement benefits costs, primarily due to pension curtailment charges associated with announced plant closures	(0.1		)	5.7
Increase in group insurance expenses	3.1			3.8
Increase / (decrease) in generating facilities operating and maintenance expenses	(0.5		)	3.2
Other, net	3.3			(3.8		)
Net change in operating expenses	$	(870.4	)	$	(793.2	)

(a) During the six months ended June 30,2017, the Generation segment recorded a fixed-asset impairment of $66.3 million. The Generation segment recognized asset impairment expense of $39.1 million and $27.3 million for Stuart Station and Killen Station, respectively. During the six months ended June 30,2016, the Generation segment recorded a fixed-asset impairment of $857.1 million. The Generation segment recognized asset impairment expense of $230.8 million and $4.7 million for Killen Station and certain DP&L peaking generating facilities, respectively. For more information, see Note 14 – Fixed-asset Impairments of Notes to DPL's Condensed Consolidated Financial Statements.

(b) During the three months ended June 30, 2017, the Generation segment recorded a gain on asset disposal of $3.2 million to offset the net loss recorded on the disposal of assets in the first quarter of 2017 related to the high pressure feedwater heater shell failure on Unit 1 at Stuart station, due to additional accrued insurance recoveries. During the six months ended June 30,2017, the Generation segment recorded a loss on asset disposal of $16.2 million related to the write-off of plant materials and supplies inventory at the Stuart and Killen plants. There was also a $6.4 million loss recorded on the disposal of assets related to the high pressure feedwater heater shell failure on Unit 1 at Stuart station; however, this was completely offset by accrued insurance proceeds.

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DPL Inc. –Generation Segment – Interest Expense

During the three and six months ended June 30, 2017, Interest expense did not change significantly compared to the same periods in the prior year.

In the generation separation order dated September 17, 2014, the PUCO permitted DP&L, upon transfer of the generation assets to AES Ohio Generation, to temporarily maintain long-term debt of $750.0 million or 75% of its rate base, whichever is greater, until January 1, 2018. For segment purposes, $750.0 million of long-term debt and the pro rata interest expense associated with that debt has been allocated to the T&D segment. All remaining debt and interest expense has been included in the Generation segment.

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RESULTS OF OPERATIONS HIGHLIGHTS – DP&L

	Three months ended June 30,						Six months ended June 30,
$ in millions	2017			2016			2017			2016
Revenues:
Retail	$	151.7		$	168.9		$	323.9		$	356.4
Wholesale	90.4			101.9			188.9			219.3
RTO revenues	13.2			14.2			26.5			28.7
RTO capacity revenues	28.8			28.9			55.9			58.6
Other mark-to-market losses	—			(0.2		)	—			(0.1		)
Total revenues	284.1			313.7			595.2			662.9
Cost of revenues:
Fuel costs	50.2			57.3			100.6			121.9
Gains from the sale of coal	(0.3		)	(1.3		)	(0.6		)	(3.0		)
Mark-to-market gains	—			(0.4		)	—			(0.4		)
Total fuel	49.9			55.6			100.0			118.5
Purchased power	59.4			77.5			136.4			168.9
RTO charges	16.3			16.1			36.9			36.4
RTO capacity charges	3.2			6.0			6.1			14.1
Mark-to-market gains	(2.5		)	(2.9		)	(2.2		)	(1.4		)
Total purchased power	76.4			96.7			177.2			218.0
Total cost of revenues	126.3			152.3			277.2			336.5
Gross margin	157.8			161.4			318.0			326.4
Operating expenses:
Operation and maintenance	80.9			76.4			163.5			162.5
Depreciation and amortization	22.0			36.8			45.5			71.1
General taxes	23.6			21.1			47.2			41.6
Gain on termination of contract	—			—			—			(27.7		)
Fixed-asset impairment	—			857.1			66.3			857.1
Loss / (gain) on asset disposal	(3.2		)	0.1			16.2			0.2
Total operating expenses	123.3			991.5			338.7			1,104.8
Operating income	34.5			(830.1		)	(20.7		)	(778.4		)
Other expense, net
Investment income	0.1			0.3			0.1			0.2
Interest expense	(7.8		)	(5.4		)	(15.4		)	(10.7		)
Charge for early redemption of debt	(0.1		)	—			(0.1		)	—
Other expense	(0.4		)	(0.1		)	(1.3		)	(0.3		)
Total other expense, net	(8.2		)	(5.2		)	(16.7		)	(10.8		)
Income / (loss) from operations before income tax (a)	$	26.3		$	(835.3	)	$	(37.4	)	$	(789.2	)

(a) For purposes of discussing operating results, we present and discuss Income / (loss) 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.

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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; 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			Six months ended
	June 30,			June 30,
$ in millions	2017 vs. 2016			2017 vs. 2016
Retail
Rate	$	(13.9	)	$	(18.3	)
Volume	(4.3		)	(18.7		)
Other miscellaneous	1.0			4.5
Total retail change	(17.2		)	(32.5		)
Wholesale
Rate	(5.9		)	(18.6		)
Volume	(5.6		)	(11.8		)
Total wholesale change	(11.5		)	(30.4		)
RTO revenues and RTO capacity revenues
RTO revenues and RTO capacity revenues	(1.1		)	(4.9		)
Other
Unrealized MTM	0.2			0.1
Total revenues change	$	(29.6	)	$	(67.7	)

During the three months ended June 30, 2017, Revenues decreased $29.6 million to $284.1 million from $313.7 million in the same period in the prior year. This decrease was primarily the result of lower average retail and wholesale rates, lower retail and wholesale volumes, and lower RTO revenues and RTO capacity revenues. The changes in the components of revenue are discussed below:

• Retail revenues decreased $17.2 million primarily due to lower average DP&L retail rates and lower DP&L retail volumes. The decrease in average retail rates was primarily driven by reverting to ESP 1 rates in September of 2016 and a decrease in the USF revenue rate rider, partially offset by increased revenue associated with energy efficiency programs recorded in 2017. The decrease in retail volume was primarily driven by more mild weather in 2017, as heating degree days decreased by 212 degree days and cooling degree days decreased by 25 degree days. The aforementioned impacts resulted in an unfavorable $13.9 million retail price variance and an unfavorable $4.3 million retail volume variance. These variances were partially offset by a favorable other miscellaneous variance of $1.0 million.

• Wholesale revenues decreased $11.5 millionprimarily as a result of an unfavorable $5.9 million wholesale price variance and an unfavorable $5.6 million wholesale volume variance. Despite year over year increases in PJM market prices, average wholesale rates decreased due to higher rates on contracted sales to serve the load of other parties in 2016 as well as hedged transactions in both years. The decrease

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in wholesale volumes of $5.6 million was primarily driven by a decrease in the load served of other parties through their competitive bid process and a 2% decrease in internal generation at DP&L's plants in 2017.

• 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 $1.1 million compared to the same period in the prior year. This decrease was the result of a $1.0 million decrease in RTO revenues due to lower rates related to compensation for DP&L's reactive supply and operating reserves. In addition, there was a $0.1 million decrease in revenue realized from the PJM capacity auction in 2017.

During the six months ended June 30,2017, Revenues decreased $67.7 million to $595.2 million from $662.9 million in the same period in the prior year. This decrease was primarily the result of lower average retail and wholesale rates, lower retail and wholesale volumes, and lower RTO revenues and RTO capacity revenues. The changes in the components of revenue are discussed below:

• Retail revenues decreased $32.5 millionprimarily due to lower average DP&L retail rates and lower DP&L retail volumes. The decrease in average retail rates was primarily driven by reverting to ESP 1 rates in September of 2016, collections on the remaining 2015 deferred fuel balance in the first quarter of 2016, and a decrease in the USF revenue rate rider, partially offset by increased revenue associated with energy efficiency programs recorded in 2017. The decrease in retail volume was primarily driven by more mild weather in 2017, as heating degree days decreased by 496 degree days and cooling degree days decreased by 23 degree days. The aforementioned impacts resulted in an unfavorable $18.7 million retail volume variance and an unfavorable $18.3 million retail price variance. These variances were partially offset by a favorable other miscellaneous variance of $4.5 million.

• Wholesale revenues decreased $30.4 millionprimarily as a result of an unfavorable $18.6 million wholesale price variance and an unfavorable $11.8 million wholesale volume variance. Despite year over year increases in PJM market prices, average wholesale rates decreased due to higher rates on contracted sales to serve the load of other parties in 2016 as well as hedged transactions in both years. The decrease in wholesale volumes of $11.8 million was primarily driven by a decrease in the load served of other parties through their competitive bid process and a 1% decrease in internal generation at DP&L's plants in 2017.

• 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 $4.9 million compared to the same period in the prior year. This decrease was the result of a $2.7 million decrease in revenue realized from the PJM capacity auction in 2017 primarily due to lower prices in both the CP and RPM auctions as well as less capacity cleared year over year. 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, and $136/MW-day in June of 2015. There was also a $2.2 million decrease in RTO revenues due to lower rates related to compensation for DPL's reactive supply and operating reserves.

DP&L – Cost of Revenues

During the three months ended June 30, 2017, Cost of revenues decreased $26.0 million compared to the same period in the prior year:

• Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $5.7 million, compared to the same period in the prior year primarily due to an 11% decrease in average fuel cost per MWh and a 2% decrease in internal generation at DP&L's plants in 2017.

• Net purchased power decreased $20.3 million compared to the prior year. This decrease was driven by the following factors:

◦ Purchased power decreased $18.1 million primarily due to a $10.8 million volume decrease and a $7.3 million price decrease compared to the same period in the prior year. The volume decrease was primarily driven by a lower load served through the competitive bid process of other parties compared to 2016, as well as the decrease in DP&L retail demand in 2017. The price decrease was primarily driven by lower rates in the competitive bid process in 2017 than 2016.

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◦ RTO charges increased $0.2 million compared to the same period in the prior year. 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 TCRR-N rider, transmission and congestion losses incurred on DP&L's wholesale revenues, and costs associated with load obligations for retail customers.

◦ RTO capacity charges decreased $2.8 million compared to the same period in the prior year primarily due to a lower retail load served in 2017. Retail load served relates to the load of other parties through their competitive bid process. As noted in the Revenues section above, RTO capacity prices are set by an annual auction.

◦ Mark-to-market gains decreased $0.4 million compared to the same period in the prior year due to changes in power prices in 2017 and 2016.

During the six months ended June 30,2017, Cost of revenues decreased $59.3 million compared to the same period in the prior year:

• Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $18.5 million, compared to the same period in the prior year primarily due to a 16% decrease in average fuel cost per MWh and a 1% decrease in internal generation. There were fuel costs deferred in 2015, which were expensed in 2016 because they were collected in 2016, which contributed to the price decrease. There were no fuel costs deferred or collected in 2017.

• Net purchased power decreased $40.8 million compared to the prior year. This decrease was driven by the following factors:

◦ Purchased power decreased $32.5 million primarily due to a $24.8 million volume decrease and a $7.7 million price decrease compared to the same period in the prior year. The volume decrease was primarily driven by a lower load served through the competitive bid process of other parties compared to 2016, as well as the decrease in DP&L retail demand in 2017. The price decrease was primarily driven by lower rates in the competitive bid process in 2017 than 2016.

◦ RTO charges increased $0.5 million compared to the same period in the prior year. 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 TCRR-N rider, transmission and congestion losses incurred on DP&L's wholesale revenues, and costs associated with load obligations for retail customers.

◦ RTO capacity charges decreased $8.0 million compared to the same period in the prior year primarily due to a lower retail load served in 2017, as well as a $1.7 million PJM penalty incurred in March 2016 associated with low plant availability. Retail load served relates to the load of other parties through their competitive bid process. As noted in the Revenues section above, RTO capacity prices are set by an annual auction.

◦ Mark-to-market gains increased $0.8 million compared to the same period in the prior year due to changes in power prices in 2017 and 2016.

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DP&L – Operation and Maintenance

During the three and six months ended June 30, 2017, Operation and Maintenance expense increased $4.5 million and $1.0 million, respectively, compared to the same periods in the prior year. The main drivers of these changes are as follows:

	Three months ended			Six months ended
	June 30,			June 30,
$ in millions	2017 vs. 2016			2017 vs. 2016
Increase in group insurance expense	$	6.4		$	7.2
Increase in retirement benefits costs, primarily due to pension curtailment charges associated with announced plant closures	0.6			6.9
Increase / (decrease) in generating facilities operating and maintenance expenses	(0.8		)	1.3
Decrease in uncollectible expenses for the low-income payment program, which is funded by the USF revenue rate rider (a)	(5.0		)	(12.0		)
Other, net	3.3			(2.4		)
Net change in operation and maintenance expense	$	4.5		$	1.0

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

DP&L – Depreciation and Amortization

During the three and six months ended June 30, 2017, Depreciation and amortization decreased $14.8 million and $25.6 million respectively, compared to the same periods in the prior year. The decrease was primarily a result of the fixed-asset impairments in the second and fourth quarters of 2016 and the first quarter of 2017, which reduced depreciation expense due to the lower asset values. In addition, the decrease was attributable to the discontinuation of Miami Fort and Zimmer depreciation expense due to the pending sale of these two plants.

DP&L – General Taxes

During the three months ended June 30, 2017, General taxes increased $2.5 million compared to the same period in the prior year. The increase was primarily the result of a $1.2 million true-up of the 2016 Ohio property tax accrual to reflect actual payments made in 2017, and a $0.4 million increase in the 2017 accrual to reflect a higher estimated 2017 liability.

During the six months ended June 30,2017, General taxes increased $5.6 million compared to the same period in the prior year. The increase was primarily the result of lower expense in 2016 due to a $1.6 million favorable true-up of the 2015 Ohio property tax accrual to reflect actual payments made in 2016. In addition, 2017 expense was higher due to a $1.6 million unfavorable true-up of the 2016 and 2017 Ohio property tax accruals to reflect actual payments made in 2017 and higher rates.

DP&L – Gain on Termination of Contract

During the six months ended June 30, 2016, DP&L recorded $27.7 million related to the termination of a contract DP&L had with DPLER for the supply of electricity.

DP&L – Fixed-asset Impairment

During the six months ended June 30,2017, DP&L recorded an impairment of fixed-assets of $66.3 million. DP&L recognized asset impairment expense of $39.0 million and $27.3 million for Stuart Station and Killen Station, respectively. For more information, see Note 14 – Fixed-asset Impairments of Notes to DP&L's Condensed Financial Statements.

During the three and six months ended June 30, 2016, DP&L recorded an impairment of fixed assets of $857.1 million. A ruling by the Supreme Court of Ohio on June 20, 2016, lower expectation of future capacity revenue resulting from the most recent PJM capacity auction and a higher anticipated level of environmental compliance costs resulting from third party studies were collectively determined to be an impairment indicator for these assets. We performed a long-lived asset impairment test and determined that the carrying amounts of the asset groups of Killen and certain DP&L peaking generating facilities were not recoverable. For more information, see Note 14 – Fixed-asset Impairments of Notes to DP&L's Condensed Financial Statements.

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DP&L – Loss on Asset Disposal

During the three months ended June 30, 2017, DPL recorded a gain on asset disposal of $3.2 million to offset the net loss recorded on the disposal of assets in the first quarter of 2017 related to the high pressure feedwater heater shell failure on Unit 1 at Stuart station, due to additional accrued insurance recoveries.

During the six months ended June 30,2017, DP&L recorded a loss on asset disposal of $16.2 million related to the write-off of plant materials and supplies inventory at the Stuart and Killen plants. There was also a $6.4 million loss recorded on the disposal of assets related to the high pressure feedwater heater shell failure on Unit 1 at Stuart station; however, this was completely offset by accrued insurance proceeds.

DP&L – Interest Expense

During the three months ended June 30, 2017, Interest expense increased $2.4 million compared to the same period in the prior year primarily due to higher interest rates on the $445.0 million variable rate Term Loan B maturing on August 24, 2022 compared to the interest rate on the 1.875% First Mortgage Bonds Due 2016.

During the six months ended June 30,2017, Interest expense increased $4.7 million compared to the same period in the prior year primarily due to higher interest rates on the $445.0 million variable rate Term Loan B maturing on August 24, 2022 compared to the interest rate on the 1.875% First Mortgage Bonds Due 2016.

DP&L – Income Tax Expense

During the three months ended June 30, 2017, Income tax expense / (benefit) increased $313.9 million compared to the same period in the prior year primarily due to pre-tax income in the current year versus a pre-tax loss in the prior year.

During the six months ended June 30,2017, Income tax benefit decreased $279.6 million compared to the same period in the prior year primarily due to a significantly lower pre-tax loss in the current year versus the prior year.

RESULTS OF OPERATIONS BY SEGMENT – DP&L

During the fourth quarter of 2016, DP&L’s management reassessed the separate reportable business segments in connection with recent changes in the regulatory environment, including the pending ESP case, and in preparation for the anticipated transfer of DP&L’s generation assets to AES Ohio Generation. DP&L currently manages the business through two reportable operating segments, the T&D segment and the Generation segment. The primary segment performance measure is income / (loss) from operations before income tax as management has concluded that this measure best reflects the underlying business performance of DP&L and is the most relevant measure considered in DP&L’s internal evaluation of the financial performance of its segments. The segments are discussed further below:

Transmission and Distribution Segment

The segment description and the results of operations of the T&D segment for DP&L are identical in all material respects and for all periods presented to those of the T&D segment for DPL,which are included above in this Form 10-Q. We do not believe that additional discussions of the results of operations of DP&L’s T&D segment would enhance an understanding of this business since these discussions are already included under the DPL discussions above.

Generation Segment

The Generation segment is comprised of DP&L’s electric generation business. Beginning in 2001, Ohio law gave consumers the right to choose the electric generation supplier from whom they purchase retail generation services. DP&L's generation segmentowns multiple coal-fired and peaking electric generating facilities. DP&L's generation segment sells its generated energy and capacity into the wholesale market as DP&L sources all of the generation for its SSO customers through a competitive bid process.

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 DP&L’s Condensed Financial Statements for additional information regarding DP&L’s reportable segments.

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

	Three months ended June 30,					Six months ended June 30,
$ in millions	2017		2016			2017			2016
T&D	$	15.1	$	30.1		$	40.1		$	64.5
Generation	11.2		(865.4		)	(77.5		)	(853.7		)
Income / (loss) from operations before income tax (a)	$	26.3	$	(835.3	)	$	(37.4	)	$	(789.2	)

(a) For purposes of discussing operating results, we present and discuss Income / (loss) 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 that is used by management to make decisions regarding our financial performance.

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Statement of Operations Highlights – DP&L – Generation Segment

	Three months ended June 30,						Six months ended June 30,
$ in millions	2017			2016			2017			2016
Revenues:
Retail	$	0.1		$	0.1		$	0.1		$	0.1
Wholesale	86.9			98.5			180.3			212.3
RTO revenues	1.7			2.8			3.5			6.0
RTO capacity revenues	27.2			27.4			53.0			55.0
Other mark-to-market losses	—			(0.2		)	—			(0.1		)
Total revenues	115.9			128.6			236.9			273.3
Cost of revenues:
Cost of fuel:
Fuel costs	50.2			57.3			100.6			116.3
Gains from the sale of coal	(0.3		)	(1.3		)	(0.6		)	(2.7		)
Mark-to-market gains	—			(0.4		)	—			(0.4		)
Net fuel costs	49.9			55.6			100.0			113.2
Purchased power:
Purchased power	6.1			17.4			16.4			42.9
RTO charges	3.2			2.5			9.4			7.8
RTO capacity charges	3.1			5.7			6.0			14.5
Mark-to-market gains	(2.5		)	(2.9		)	(2.2		)	(1.4		)
Net purchased power	9.9			22.7			29.6			63.8
Total cost of revenues	59.8			78.3			129.6			177.0
Gross margin	56.1			50.3			107.3			96.3
Operating expenses:
Operation and maintenance	40.7			35.1			84.5			74.9
Depreciation and amortization	3.4			19.2			8.8			36.3
General taxes	4.0			3.7			8.7			8.6
Gain on termination of contract	—			—			—			(27.7		)
Fixed-asset impairment	—			857.1			66.3			857.1
Loss / (gain) on asset disposal	(3.2		)	0.6			16.2			0.6
Total operating expenses	44.9			915.7			184.5			949.8
Operating income / (loss)	11.2			(865.4		)	(77.2		)	(853.5		)
Other expense, net
Investment income	—			0.1			—			—
Interest expense	—			(0.1		)	(0.2		)	(0.2		)
Other expense	—			—			(0.1		)	—
Total other expense, net	—			—			(0.3		)	(0.2		)
income / (loss) from operations before income tax (a)	$	11.2		$	(865.4	)	$	(77.5	)	$	(853.7	)

(a) For purposes of discussing operating results, we present and discuss Income / (loss) 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 that is used by management to make decisions regarding our financial performance.

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DP&L –Generation Segment – Revenues

During the three months ended June 30, 2017, the segment’s revenues decreased $12.7 million to $115.9 million from $128.6 million in the same period of the prior year. This decrease was primarily the result of lower wholesale volumes and rates and lower RTO capacity and other revenues.

• Wholesale revenues decreased $11.6 million primarily as a result of an unfavorable wholesale price variance of $10.7 million and an unfavorable wholesale volume variance of $0.9 million. Despite increases in PJM market prices, the unfavorable price variance was due to lower realized gains on derivatives in 2017. The decrease in wholesale volumes was primarily driven by a decrease in the load served of other parties through their competitive bid process in 2017 compared to the prior year and a 2% decrease in internal generation at DP&L's plants in 2017.

• RTO capacity and other revenues decreased $1.3 million compared to same period in the prior year.

During the six months ended June 30,2017, the segment’s revenues decreased $36.4 million to $236.9 million from $273.3 million in the same period of the prior year. This decrease was primarily the result of lower wholesale volumes and rates and lower RTO capacity and other revenues.

• Wholesale revenues decreased $32.0 million primarily as a result of an unfavorable wholesale price variance of $20.5 million and an unfavorable wholesale volume variance of $11.5 million. Despite increases in PJM market prices, the unfavorable price variance was due to lower realized gains on derivatives in 2017. The decrease in wholesale volumes was primarily driven by a decrease in the load served of other parties through their competitive bid process in 2017 compared to the prior year and a 1% decrease in internal generation at DP&L's plants in 2017.

• RTO capacity and other revenues, consisting primarily of PJM capacity payments, decreased $4.5 million compared to same period in the prior year. This decrease was the result of a $2.0 million decrease in revenue realized from the PJM capacity auction in 2017 primarily due to lower prices in both the CP and RPM auctions as well as less capacity cleared year over year. 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, and $136/MW-day in June of 2015. There was also a $2.5 million decrease in RTO revenues due to lower rates related to compensation for DP&L's reactive supply and operating reserves.

DP&L –Generation Segment – Cost of Revenues

During the three months ended June 30, 2017, Total cost of revenues decreased $18.5 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 $5.7 million compared to the same period in the prior year primarily due to an 11% decrease in average fuel cost per MWh and a 2% decrease in internal generation at DP&L's plants in 2017.

• Net purchased power decreased $12.8 million compared to the prior year. This decrease was driven by the following factors:

◦ Purchased power decreased $11.3 million primarily due to a favorable volume variance of $10.1 million and a favorable price variance of $1.2 million. The decrease in volume was driven by a lower load served of other parties through their competitive bid process in 2016. The generation segment 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.

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

◦ RTO capacity charges decreased $2.6 million compared to the same period in the prior year primarily due to a lower retail load served in 2017. Retail load served relates to the load of other parties through their competitive bid process. As noted in the Revenues section above, RTO capacity prices are set by an annual auction.

◦ Mark-to-market gains decreased $0.4 million due to changes in power prices in 2017 and 2016.

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During the six months ended June 30,2017, Total cost of revenues decreased $47.4 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 $13.2 million compared to the same period in the prior year primarily due to a 13% decrease in average fuel cost per MWh and a 1% decrease in internal generation at DP&L's plants in 2017.

• Net purchased power decreased $34.2 million compared to the prior year. This decrease was driven by the following factors:

◦ Purchased power decreased $26.5 million primarily due to a favorable volume variance of $27.1 million, partially offset by an unfavorable price variance of $0.6 million. The decrease in volume was driven by a lower load served of other parties through their competitive bid process in 2016. The generation segment 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.

◦ RTO charges increased $1.6 million compared to the same period in the prior year.

◦ RTO capacity charges decreased $8.5 million compared to the same period in the prior year primarily due to a lower retail load served in 2017, as well as a $1.7 million PJM penalty incurred in March 2016 associated with low plant availability. Retail load served relates to the load of other parties through their competitive bid process. As noted in the Revenues section above, RTO capacity prices are set by an annual auction.

◦ Mark-to-market gains increased $0.8 million due to changes in power prices in 2017 and 2016.

DP&L –Generation Segment – Operating Expenses

During the three and six months ended June 30, 2017, Operating expenses decreased $870.8 million and $765.3 million, respectively, compared to the same periods in the prior year. The main drivers of these changes are as follows:

	Three months ended June 30,			Six months ended June 30,
$ in millions	2017 vs. 2016			2017 vs. 2016
Change in Fixed-asset impairment from 2016 to 2017 (a)	(857.1		)	$	(790.8	)
Decrease in Depreciation and amortization expense as a result of the fixed-asset impairments in the second and fourth quarters of 2016 and the first quarter of 2017, which reduced depreciation expense due to the lower asset values	(15.8		)	(27.5		)
Gain on termination of contract in 2016	—			27.7
Loss / (gain) on asset disposal (b)	(3.2		)	16.2
Increase / (decrease) in retirement benefits costs, primarily due to pension curtailment charges associated with announced plant closures	(0.1		)	5.8
Increase in group insurance expense	3.0			3.7
Increase / (decrease) in generating facilities operating and maintenance expenses	(0.8		)	1.6
Other, net	3.2			(2.0		)
Net change in operating expenses	$	(870.8	)	$	(765.3	)

(a) During the six months ended June 30,2017, the Generation segment recorded a fixed-asset impairment of $66.3 million. The Generation segment recognized an asset impairment expense of $39.0 million and $27.3 million for Stuart Station and Killen Station, respectively. During the six months ended June 30,2016, the Generation segment recorded a fixed-asset impairment of $857.1 million. The Generation segment recognized an asset impairment expense of $292.0 million, $246.2 million and $318.9 million for Stuart Station, Killen Station and Zimmer station, respectively. For more information, see Note 14 – Fixed-asset Impairments of Notes to DP&L's Condensed Financial Statements.

(b) During the three months ended June 30, 2017, the Generation segment recorded a gain on asset disposal of $3.2 million to offset the net loss recorded on the disposal of assets in the first quarter of 2017 related to the high pressure feedwater heater shell failure on Unit 1 at Stuart station, due to additional accrued insurance recoveries. During the six months ended June 30,2017, the Generation segment recorded a loss on asset disposal of $16.2 million related to the write-off of plant materials and supplies inventory at the Stuart and Killen plants. There was also a $6.4 million loss recorded on the disposal of assets related to the high pressure feedwater heater shell failure on Unit 1 at Stuart station; however, this was completely offset by accrued insurance proceeds.

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DP&L –Generation Segment – Interest Expense

During the three and six months ended June 30, 2017, Interest expense did not change significantly compared to the same periods in the prior year.

In the generation separation order dated September 17, 2014, the PUCO permitted DP&L, upon transfer of the generation assets to AES Ohio Generation, to temporarily maintain long-term debt of $750.0 million or 75% of its rate base, whichever is greater, until January 1, 2018. For segment purposes, $750.0 million of long-term debt and the pro rata interest expense associated with that debt has been allocated to the T&D segment. All remaining debt and interest expense has been included in the Generation segment.

KEY TRENDS AND UNCERTAINTIES

During the remainder of 2017 and beyond, we expect that our financial results will be driven primarily by retail demand, weather, energy efficiency and wholesale prices. In addition, DPL's and DP&L's financial results are likely to be driven by many factors including, but not limited to:

• PJM capacity prices;

• Outcome of DP&L's pending ESP 3 case, including the amount of non-bypassable revenue;

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

• Operational performance of generation facilities;

• Recovery in the power market, particularly as it relates to an expansion in dark spreads;

• Sale or transfer of DP&L generation assets; and

• DPL's ability to reduce its cost structure.

Operational

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 on or before June 1, 2018, and the co-owners of these facilities agreed with DP&L to proceed with this plan of retirement. In the first quarter of 2017, DPL incurred an impairment charge of $66.4 million and DP&L incurred an impairment charge of $66.3 million related to these planned retirements. See Note 14 – Fixed-asset Impairments of Notes to DPL's Condensed Consolidated Financial Statements and Note 14 – Fixed-asset Impairments of Notes to DP&L's Condensed Financial Statements for more information. DPL and DP&L also recorded pension curtailment charges of $4.1 million and $5.6 million, respectively, and inventory write off charges of $16.2 million in the first quarter of 2017 associated with the planned retirement.

In addition to the charges noted above, DPL and DP&L estimate that they will incur $7.0 million to $11.0 million in severance and benefit related costs during 2017 and 2018 and approximately $10.0 million to $30.0 million in plant shutdown costs, the timing of which is uncertain as of the date of this report. In addition, DPL also estimates future cash expenditures of approximately $130.0 million for asset retirement obligations beginning in June 2018 and through 2023.

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

Regulatory Environment

For a comprehensive discussion of the market structure and regulation of DPL and DP&L, see Part I, Item 2 - OHIO COMPETITION AND REGULATORY PROCEEDINGS.

DP&L originally filed its ESP 3 seeking an effective date of January 1, 2017. On October 11, 2016, DP&L amended the application requesting to collect $145.0 million per year for seven years, named the Distribution Modernization Rider ("DMR"). This plan established the terms and conditions for DP&L’s SSO to customers that do not choose a competitive retail electric supplier, and recommended including renewable energy attributes as part of the product that is competitively bid. DP&L sought recovery of approximately $10.5 million of regulatory assets, and proposed a new Distribution Investment Rider to allow DP&L to recover costs associated with future distribution equipment

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and infrastructure needs. Additionally, the plan established new riders set initially at zero, related to energy reductions from DP&L’s energy efficiency programs, and certain environmental liabilities.

On January 30, 2017, DP&L, in conjunction with various intervening parties, filed a settlement in the ESP 3 case. On March 13, 2017, DP&L, in conjunction with various intervening parties and the staff of the PUCO, filed an amended stipulation in the ESP 3 case, which is subject to PUCO approval. The intervening parties agreed to a six-year settlement that provides a framework for energy rates and defines components which include, but are not limited to, the following:

• Bypassable standard offer energy rates for DP&L’s customers based on competitive bid auctions;

• The establishment of a three-year non-bypassable DMR designed to collect $105.0 million in revenue per year to pay debt obligations at DPL and DP&L and position DP&L to modernize and/or maintain its transmission and distribution infrastructure. With PUCO approval, DP&L has the option of extending the duration of the DMR for an additional two years;

• The establishment of a non-bypassable Distribution Investment Rider, set initially at zero, to recover incremental distribution capital investments;

• The establishment of a Smart Grid Rider, set initially at zero, to recover costs of future grid modernization;

• A commitment by us to separate DP&L’s generation assets from its transmission and distribution assets (if approved by FERC) within 180 days after receipt of a PUCO order;

• A commitment to commence a sale process to sell our ownership interests in the Zimmer, Miami Fort and Conesville coal-fired generation plants; and

• Restrictions on DPL making dividend or tax sharing payments, and various other riders and competitive retail market enhancements.

A hearing was held in April 2017 and a final decision by the PUCO is expected in the third quarter of 2017. There can be no assurance that the amended ESP 3 stipulation will be approved as filed or on a timely basis, and if the Amended ESP 3 stipulation is not approved on a timely basis or if the final ESP provides for terms that are more adverse than those submitted in DP&L's amended stipulation, our results of operations, financial condition and cash flows and DPL's ability to meet long-term obligations, in the periods beyond twelve months from the date of this report, could be materially impacted.

On April 21, 2017, DP&L and AES Ohio Generation entered into an agreement for the sale of DP&L’s undivided interests in Zimmer and Miami Fort for $50.0 million in cash and the assumption of certain liabilities, including environmental liabilities. The purchase price is subject to adjustment at closing based on the amount of certain inventories, pre-paid amounts, employment benefits, insurance premiums, property taxes and other costs. The sale is subject to approval by the FERC and is expected to close in the third quarter of 2017.

In connection with any sale or closure of our generation plants as contemplated by the ESP 3 settlement or otherwise, DPL and DP&L would expect to incur certain cash and non-cash charges, some or all of which could be material to the business and financial condition of DPL and DP&L.

DP&L’s ESP 2 had been approved by the PUCO for the years 2014 - 2016, and permitted DP&L to collect a non-bypassable service stability rider equal to $110.0 million per year for each of those years and required DP&L to conduct competitive bid auctions to procure generation supply for SSO service. The Ohio Supreme Court in a June 2016 opinion stated that the PUCO’s approval of the ESP was reversed. In view of that reversal, DP&L filed a motion to withdraw its ESP 2 and implement rates consistent with those in effect prior to 2014. The PUCO approved DP&L’s withdrawal of ESP 2 and implementation plans. Those rates will be in effect until rates approved as a result of DP&L’s pending ESP 3 are effective. In February 2017, several parties appealed the PUCO orders that approved both the withdrawal and the implementation plans to the Ohio Supreme Court. Those appeals are pending and the outcome and potential financial impact of those appeals cannot be determined at this time. In July 2017, the Office of the Ohio Consumers Counsel filed a motion with the Ohio Supreme Court seeking to stay collection of the reinstated prior rates while the appeals are pending.

Environmental

We refer to the discussion in “Item 1. Business - Environmental Matters - Climate Change Legislation and Regulation” in our 2016 Form 10-K for a discussion of certain recent developments in environmental laws and regulations, including the USEPA’s CO₂ emissions rules for new electric generating units, or GHG NSPS, as well as the CO₂ emissions rules for existing power plants, called the CPP. Both the GHG NSPS and the CPP are being challenged by several states and industry groups in the D.C. Circuit Court. The challenges to the CPP have been

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fully briefed and argued but oral arguments have not yet taken place on the GHG NSPS. On March 28, 2017, the USEPA filed a motion in the D.C. Circuit Court to hold the challenges to both the CPP and the GHG NSPS in abeyance in light of an Executive Order signed the same day. On April 28, 2017, the D.C. Circuit Court issued orders holding the challenges to both rules in abeyance for 60 days. The Executive Order instructs the USEPA administrator to review the GHG NSPS and CPP and “if appropriate ... as soon as practicable ... publish for notice and comment proposed rules suspending, revising, or rescinding those rules.” On April 4, 2017, the USEPA published a notice in the Federal Register to announce that it is initiating administrative reviews of both the CPP and the GHG NSPS as a result of the Executive Order.

On July 20, 2017, the Maryland Department of the Environment notified the USEPA that it was considering suing the USEPA for failing to address its November 2016 CAA petition to the USEPA to determine that 36 electric generating units in five upwind states, including DP&L's Killen unit, emit pollutants that contribute to non-attainment of National Ambient Air Quality Standards for Ozone in Maryland, as described further in our 2016 Form 10-K. If this petition is granted or a suit is filed and decided favorably to Maryland Department of the Environment, our facilities could be subject to additional requirements. In light of the scheduled retirement of the Killen unit, we do not expect any additional requirements to have a material impact on us.

On April 13, 2017, as directed by President Trump’s Executive Order 13777, the USEPA published a proposed rule called “Evaluation of Existing Regulations,” announcing the formation of a task force to evaluate regulatory burdens and soliciting comments on any federal regulations that should be considered for repeal, replacement, or modification. The task force will attempt to identify regulations that (a) eliminate jobs or inhibit job creation; (b) are outdated, unnecessary, or ineffective; (c) impose costs that exceed benefits; (d) create a serious inconsistency or otherwise interfere with regulatory reform initiatives and policies; (e) are based on data or methods that are not transparent or publicly available; and (f) are derived from or implement executive orders that have been rescinded or modified. It is unclear what impact this regulatory evaluation will have on our business.

We cannot predict at this time the likely outcome of the USEPA’s review of existing regulations. By order of the U.S. Supreme Court, the CPP has been stayed pending resolution of the challenges to the rule. Due to the future uncertainty of the CPP, we cannot at this time determine the impact on our operations or consolidated financial results, but we believe the cost to comply with the CPP, should it be upheld and implemented in its current or a substantially similar form, could be material. The GHG NSPS remains in effect at this time, and, absent further action from the USEPA that rescinds or substantively revises the NSPS, it could impact our plans to construct and/or modify or reconstruct electric generating units in some locations, which 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 $34.1 million and $6.1 million, respectively, at June 30, 2017. 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 $1,860.7 million and $752.6 million, respectively.

Approximately $50.9 million of DPL's long-term debt including $26.4 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.

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 may have material adverse effects on our financial condition and results 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.

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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	Six months ended June 30,
$ in millions	2017			2016
Net cash provided by operating activities	$	40.2		$	132.4
Net cash used in investing activities	(37.9		)	(15.9		)
Net cash used in financing activities	(22.8		)	(75.5		)
Net change	(20.5		)	41.0
Balance at beginning of period	54.6			32.4
Cash and cash equivalents at end of period	$	34.1		$	73.4

DPL - Change in cash flows from operating activities

	Six months ended June 30,						$ change
$ in millions	2017			2016			2017 vs. 2016
Net income / (loss)	(51.2		)	(105.0		)	$	53.8
Depreciation and amortization	54.5			69.4			(14.9		)
Impairment expenses	66.4			235.5			(169.1		)
Gain on sale of business	—			(49.2		)	49.2
Other adjustments to Net income / (loss)	14.7			(93.2		)	107.9
Net income / (loss), adjusted for non-cash items	84.4			57.5			26.9
Net change in operating assets and liabilities	(44.2		)	74.9			(119.1		)
Net cash provided by operating activities	$	40.2		$	132.4		$	(92.2	)

The net change in operating assets and liabilities during the six months ended June 30, 2017 compared to the six months ended June 30, 2016 was driven by the following:

$ in millions	$ Change
Decrease from accrued taxes payable primarily due to an income tax benefit from the current year loss	$	(39.6	)
Decrease from accounts receivable due to lower collections	(30.3		)
Decrease from accounts payable due to timing of spending	(26.7		)
Decrease from deferred regulatory costs, net, due to lower collections on regulatory assets and liabilities	(17.1		)
Decrease from inventory primarily due to lower coal purchases in 2016	(13.9		)
Other	8.5
Total decrease in cash from changes in operating assets and liabilities	$	(119.1	)

DPL - Cash flows from investing activities

Capital expenditures, primarily related to transmission and distribution, continue to be our principal use of cash related to investing activities. Net cash from investing activities was $(37.9) million for the six months endedJune 30, 2017 compared to $(15.9) million for the six months endedJune 30, 2016, primarily driven by a decrease in proceeds from sale of business of $75.5 million, related to the sale of DPLER in January 2016, which was partially offset by a favorable change in restricted cash of $43.5 million, related to a decrease in collateral requirements on derivatives and lower capital expenditures of $12.7 million.

DPL - Cash flows from financing activities

Net cash used in financing activities was $(22.8) million for thesix months endedJune 30, 2017 compared to $(75.5) million from financing activities for the six months endedJune 30, 2016. For thesix months endedJune 30, 2017, this was due to repayments on the DPL term loan of $12.5 million and the DP&L term loan of $2.2 million, as well as an $8.1 million partial redemption of the $100.0 million 4.8% first mortgage bonds. During the six months

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endedJune 30, 2016, there was a redemption of $73.0 million of DPL's $130.0 million 6.5% Senior Unsecured Notes Due 2016, along with the related make-whole premium payment of $2.4 million.

CASH FLOWS - DP&L

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

DP&L	Six months ended June 30,
$ in millions	2017			2016
Net cash provided by operating activities	$	57.5		$	159.5
Net cash used in investing activities	(28.7		)	(84.0		)
Net cash used in financing activities	(24.3		)	(35.5		)
Net change	4.5			40.0
Balance at beginning of period	1.6			5.4
Cash and cash equivalents at end of period	$	6.1		$	45.4

DP&L - Change in cash flows from operating activities

	Six months ended June 30,						$ change
$ in millions	2017			2016			2017 vs. 2016
Net income / (loss)	(25.7		)	(497.9		)	$	472.2
Depreciation and amortization	45.5			71.1			(25.6		)
Impairment expenses	66.3			857.1			(790.8		)
Other adjustments to Net income / (loss)	19.5			(308.5		)	328.0
Net income / (loss), adjusted for non-cash items	105.6			121.8			(16.2		)
Net change in operating assets and liabilities	(48.1		)	37.7			(85.8		)
Net cash provided by operating activities	$	57.5		$	159.5		$	(102.0	)

The net change in operating assets and liabilities during the six months ended June 30, 2017 compared to the six months ended June 30, 2016 was driven by the following:

$ in millions	$ Change
Decrease from accrued taxes payable, due to income tax benefit incurred on current year loss	$	(32.4	)
Decrease from accounts payable due to timing of spending	(24.2		)
Decrease from deferred regulatory costs, net, due to lower collections on regulatory assets and liabilities	(17.1		)
Decrease from inventory primarily due to lower coal purchases in 2016	(13.6		)
Other	1.5
Total decrease in cash from changes in operating assets and liabilities	$	(85.8	)

DP&L - Cash flows from investing activities

Net cash from investing activities was $(28.7) million for thesix months endedJune 30, 2017 compared to $(84.0) million for the six months endedJune 30, 2016, primarily due to a $43.6 million favorable change in restricted cash, due to a change in the collateral requirements on derivatives, and lower capital expenditures of $14.2 million.

DP&L - Cash flows from financing activities

Net cash used in financing activities was $(24.3) million for the six months endedJune 30, 2017 compared to $(35.5) million from financing activities for the six months endedJune 30, 2016. For the six months endedJune 30, 2017, this was due to repayments on the DP&L term loan of $2.2 million, an $8.1 million partial redemption of the $100.0 million 4.8% first mortgage bonds, and a return of capital of $9.0 million to DPL. During the six months ended June 30, 2016, DP&L repaid $40.0 million of short-term debt to its parent, DPL, partially offset by additional borrowings of $5.0 million from DPL.

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,

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scheduled debt maturities and carrying costs, potential margin requirements related to energy hedges and dividend payments. In 2017 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 June 30, 2017, DP&L and DPL have access to the following revolving credit facilities:

$ in millions	Type	Maturity	Commitment		Amounts available as of June 30, 2017
DP&L	Revolving	July 2020	$	175.0	$	173.6
DPL	Revolving	July 2020	205.0		197.6
			$	380.0	$	371.2

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 June 30, 2017, there were two letters of credit in the aggregate amount of $1.4 million outstanding under this facility, with the remaining $173.6 million available to DP&L. Fees associated with this letter of credit facility were not material during the six months ended June 30, 2017 or 2016.

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 and a limited recourse guarantee by AES Ohio Generation secured by assets of AES Ohio Generation. DPL further secured the credit facility through a leasehold mortgage on additional assets of AES Ohio Generation. The facility expires in July 2020; however, DPL's credit facility has a springing maturity feature providing that if, before July 1, 2019, DPL has not refinanced its senior unsecured bonds due October 2019 to have a maturity date that is at least six months later than July 31, 2020, then the maturity of this facility shall be July 1, 2019. At June 30, 2017, there were three letters of credit in the aggregate amount of $7.4 million outstanding under this facility, with the remaining $197.6 million available to DPL. Fees associated with this facility were not material during the six months endedJune 30, 2017 or 2016.

Capital Requirements

Planned construction additions for 2017 relate primarily to new investments in and upgrades to DP&L’s power plant equipment and transmission and distribution system. 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 $353.6 million in capital projects for the period 2017 through 2019, of which $296.7 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 $9.6 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 and the DPL term loan agreement have 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 agreements is not to exceed 7.25 to 1.00 for any fiscal quarter ending September 30, 2015 through December 31, 2018; it then steps down not to exceed 6.25 to 1.00 for any fiscal quarter ending March 31, 2019 through December 31, 2019; and it then steps down not to exceed 5.75 to 1.00 for any fiscal quarter ending March 31, 2020 through July 31, 2020. As of June 30, 2017, the financial covenant was met with a ratio of 6.86 to 1.00.

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The DPL revolving credit facility and the DPL term loan agreement also have 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 agreements, 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 June 30, 2017, this financial covenant was met with a ratio of 2.47 to 1.00.

DP&L’s revolving credit facility and Bond Purchase and Covenants Agreement have two financial covenants. Prior to the date of completion of the separation of DP&L’s generation assets from its transmission and distribution assets, DP&L’s Total Debt to Total Capitalization ratio may not be greater than 0.65 to 1.00 at any time; and, on and after the date of completion of the separation of DP&L’s generation assets from its transmission and distribution assets, DP&L’s Total debt to Total Capitalization ratio may not be greater than 0.75 to 1.00 at any time, except that (a) prior to the amendment described below, this covenant would have been suspended between January 1, 2017 and December 31, 2017, if during this same time DP&L’s long-term indebtedness (as determined by the PUCO) is less than or equal to $750.0 million or (b) this financial covenant shall be suspended at any time DP&L maintains a rating of BBB- (or in the case of Moody’s Baa3) or higher with a stable outlook from at least one of Fitch Investors Service Inc., Standard & Poor’s Ratings Services or Moody’s Investors Service, Inc., as determined in accordance with the terms of the revolving credit facility. This 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 shareholder’s equity and total debt.

On February 21, 2017, DP&L and its lenders amended DP&L’s revolving credit agreement and Bond Purchase and Covenant Agreement. These amendments modified the definition of Consolidated Net Worth (which is used for measuring the Total Debt to Total Capitalization ratio under each of the agreements), to exclude, through March 31, 2018, non-cash charges related directly to impairments of coal generation assets in DP&L's fiscal quarter ending December 31, 2016 and thereafter. With this amendment, DP&L’s Total Debt to Total Capitalization ratio for the period ending June 30, 2017 is 0.52 to 1.00. The amendment also changed, for each agreement, the dates after generation separation during which compliance with the Total Capitalization ratio detailed above shall be suspended if long-term indebtedness, as determined by the PUCO, is less than or equal to $750.0 million. This time period was originally January 1, 2017 to December 31, 2017, but is now the twelve months immediately subsequent to the separation of the generation assets from DP&L.

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 June 30, 2017, this covenant was met with a ratio of 8.20 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	BB(a) / BB-(b)	BBB (c)	Negative	July 2016
Moody's Investors Service, Inc.	Ba3 (b)	Baa2 (c)	Negative	August 2016
Standard & Poor's Financial Services LLC	B+ (b)	BBB- (c)	Negative	March 2017

(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.

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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	B+	BB+	Negative	July 2016
Moody's Investors Service, Inc.	Ba3	Baa3	Negative	August 2016
Standard & Poor's Financial Services LLC	BB-	BB-	Negative	March 2017

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 10 – Contractual Obligations, Commercial Commitments and Contingencies of Notes to DPL’s Condensed Consolidated Financial 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 Commodity Risk Management Committee (CRMC), 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 CRMC 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 DP&L-operated 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 on a monthly basis 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 2017 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.

For purposes of potential risk analysis, we use a sensitivity analysis to quantify potential impacts of market rate changes on the statements of results of operations. The sensitivity analysis represents hypothetical changes in market values that may or may not occur in the future.

Commodity Derivatives

To minimize the risk of fluctuations in the market price of commodities, such as coal, power, natural gas and heating oil, we may enter into commodity-forward and futures contracts to effectively hedge the cost/revenues of the

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commodity. Maturity dates of the contracts are scheduled to coincide with market purchases/sales of the commodity. Cash proceeds or payments between the counter-party and us at maturity of the contracts are recognized as an adjustment to the cost of the commodity purchased or sold. We generally do not enter into forward contracts beyond thirty-six months.

A 10% increase or decrease in the market price of our FTRs at June 30, 2017 would be immaterial.

At June 30, 2017, a 10% increase or decrease in the market price of our net forward power contracts and net natural gas contracts would result in a net impact on unrealized gains/losses of $(1.2) million and $1.6 million, respectively.

Wholesale Revenues

Energy in excess of contracted obligations is sold in the wholesale spot market when we can identify opportunities with positive margins. The following table presents the percentages of DPL’s and DP&L’s electric revenue derived from wholesale sales.

DPL	Six months ended
	June 30,
	2017		2016
Percent of electric revenues from wholesale market	32	%	33	%
DP&L	Six months ended
	June 30,
	2017		2016
Percent of electric revenues from wholesale market	32	%	33	%

The closure of Stuart and Killen on or before June 1, 2018 and the agreement to sell DP&L's ownership interest in Zimmer and Miami Fort will limit market exposure to wholesale power prices in future years. See Note 4 – Property, Plant and Equipment of Notes to DPL's Condensed Consolidated Financial Statements and Note 4 – Property, Plant and Equipment of Notes to DP&L's Condensed Financial Statements.

The following table presents the effect on annual Net income (net of estimated income taxes at 35%) as of June 30, 2017, of a hypothetical increase or decrease of 10% in the price per MWh of wholesale power:

$ in millions	DPL		DP&L
Effect of 10% change in price per MWh	$	29.0	$	27.6

Capacity Revenues and Costs

As a member of PJM, DP&L receives revenues from the RTO related to its transmission and generation assets and incurs costs associated with its load obligations for retail customers. PJM, which has a delivery year that runs from June 1 to May 31, has conducted auctions for capacity through the delivery year. The clearing prices for capacity during the PJM delivery periods from 2016/17 through 2020/21 are as follows:

	PJM Delivery Year
($/MW-day)	2016/17		2017/18		2018/19		2019/20		2020/21
Capacity clearing price	$	134	$	152	$	165	$	100	$	77

Our computed average capacity prices by calendar year are reflected in the following table:

	Calendar Year
($/MW-day)	2016		2017		2018		2019		2020
Computed average capacity price	$	135	$	145	$	159	$	127	$	87

The above tables reflect the capacity prices after the transitional auctions discussed earlier. Substantially all of DP&L's capacity cleared in the CP auction. The results of these auctions could have a significant effect on DP&L's revenues in the future.

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Future RPM auction results are dependent on a number of factors, which include the overall supply and demand of generation and load, other state legislation or regulation, transmission congestion and PJM’s RPM business rules. The volatility in the RPM capacity auction pricing has had and will continue to have a significant impact on DPL’s capacity revenues and costs.

The following table provides estimates of the effect on annual Net income (net of estimated income taxes at 35%) as of June 30, 2017 of a hypothetical increase or decrease of $10/MW-day in the RPM auction price. The table shows the impact resulting from capacity revenue changes. We did not include the impact of a change in the RPM capacity costs since these costs will be recovered through the development of our overall energy pricing for customers.

$ in millions	DPL		DP&L
Effect of $10/MW-day change in capacity auction pricing	$	5.4	$	4.6

Capacity revenues and costs are also impacted by, among other factors, our generation capacity, the levels of wholesale revenues and our retail customer load. In determining the capacity price sensitivity above, we did not consider the impact that may arise from the variability of these other factors.

Fuel and Purchased Power Costs

DPL’s and DP&L’s fuel (including coal, gas, oil and emission allowances) and purchased power costs as a percentage of total operating costs in the six months endedJune 30, 2017 were 38% and 38%, respectively. We have a significant portion of projected 2017 fuel needs under contract. The majority of our contracted coal is purchased at fixed prices although some contracts provide for periodic pricing adjustments. We may purchase SO₂allowances for 2017, however, the exact consumption of SO₂allowances 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 NOx allowances for 2017 depending on NOx 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 generation plant mix.

Purchased power costs depend, in part, upon the timing and extent of planned and unplanned outages of our generating capacity. We will purchase power on a discretionary basis when wholesale market conditions provide opportunities to obtain power at a cost below our internal generation costs.

The following table provides the effect on annual Net income (net of estimated income taxes at 35%) as of June 30, 2017 of a hypothetical increase or decrease of 10% in the prices of fuel and purchased power:

$ in millions	DPL		DP&L
Effect of 10% change in fuel and purchased power	$	35.6	$	34.0

Interest Rate Risk

As a result 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. DPL and DP&L have both fixed-rate and variable-rate long-term debt. DPL’s variable-rate debt consists of a $112.5 million term loan with a syndicated bank group. The term loan interest rate fluctuates with changes in an underlying interest rate index, typically LIBOR. DP&L’s 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.

We have two interest rate swaps to hedge the variable interest on our $200.0 million variable interest rate tax-exempt First Mortgage Bonds. The interest rate swaps have a combined notional amount of $200.0 million and will settle monthly based on a one month LIBOR. We use the income approach to value the swaps, which consists of forecasting future cash flows based on contractual notional amounts and applicable and available market data as of the valuation date. The most common market data inputs used in the income approach include volatilities, spot and forward benchmark interest rates (LIBOR). Forward rates with the same tenor as the derivative instrument being valued are generally obtained from published sources, with these forward rates being assessed quarterly at a

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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.

Principal Payments and Interest Rate Detail by Contractual Maturity Date

The principal value of DPL’s long-term debt was $1,860.7 million at June 30, 2017, consisting of DPL’s unsecured notes and unsecured term loan, 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 June 30, 2017 was $1,926.2 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 DPL’s long-term debt obligations that are sensitive to interest rate changes:

DPL
	Principal payments due												At June 30, 2017
	during the twelve months ending
	June 30,												Principal		Fair
$ in millions	2018		2019		2020		2021		2022		Thereafter		Amount		Value
Long-term debt (a)
Variable-rate debt	$	29.5	$	29.5	$	29.5	$	42.0	$	4.5	$	420.3	$	555.3	$	555.3
Average interest rate (b)	3.9%		3.9%		3.9%		3.8%		4.3%		4.3%
Fixed-rate debt (c)	$	22.1	$	0.2	$	200.2	$	200.2	$	780.2	$	102.5	1,305.4		1,370.9
Average interest rate	4.8%		4.2%		6.7%		2.0%		7.2%		5.2%
Total													$	1,860.7	$	1,926.2

(a) Amounts exclude immaterial capital lease obligations

(b) Based on rates in effect at June 30, 2017

(c) Fixed-rate debt includes $200.0 millionDP&L Tax-exempt First Mortgage Bonds, which are variable rate, that have been hedged, per discussion above. See Note 6 – Derivative Instruments and Hedging Activities of Notes to DPL's Condensed Consolidated Financial Statements

The principal value of DP&L’s long-term debt was $752.6 million at June 30, 2017, 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 $753.0 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 June 30, 2017
	during the twelve months ending
	June 30,												Principal		Fair
$ in millions	2018		2019		2020		2021		2022		Thereafter		Amount		Value
Long-term debt (a)
Variable-rate debt	$	4.5	$	4.5	$	4.5	$	4.5	$	4.5	$	420.3	$	442.8	$	442.8
Average interest rate (b)	4.3%		4.3%		4.3%		4.3%		4.3%		4.3%
Fixed-rate debt (c)	$	22.1	$	0.2	$	0.2	$	200.2	$	0.2	$	86.9	309.8		310.2
Average interest rate	4.8%		4.2%		4.2%		2.0%		4.2%		4.7%
Total													$	752.6	$	753.0

(a) Amounts exclude immaterial capital lease obligations

(b) Based on rates in effect at June 30, 2017

(c) Fixed-rate debt includes $200.0 millionDP&L Tax-exempt First Mortgage Bonds, which are variable rate, that have been hedged, per discussion above. See Note 6 – Derivative Instruments and Hedging Activities of Notes to DP&L's Condensed Financial Statements

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 June 30, 2017 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

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expected actual loss, even under adverse conditions, because actual adverse fluctuations would likely differ. As of June 30, 2017, 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 June 30, 2017				One percent
	Principal		Fair		interest rate
$ in millions	Amount		Value		risk
Long-term debt (a)
Variable-rate debt	$	555.3	$	555.3	$	5.6
Fixed-rate debt (b)	1,305.4		$	1,370.9	13.7
Total	$	1,860.7	$	1,926.2	$	19.3

(a) Amounts exclude immaterial capital lease obligations

(b) Fixed-rate debt includes $200.0 millionDP&L Tax-exempt First Mortgage Bonds, which are variable rate, that have been hedged, per discussion above. See Note 6 – Derivative Instruments and Hedging Activities of Notes to DPL's Condensed Consolidated Financial Statements

DP&L	At June 30, 2017				One percent
	Principal		Fair		interest rate
$ in millions	Amount		Value		risk
Long-term debt (a)
Variable-rate debt	$	442.8	$	442.8	$	4.4
Fixed-rate debt (b)	309.8		310.2		3.1
Total	$	752.6	$	753.0	$	7.5

(a) Amounts exclude immaterial capital lease obligations

(b) Fixed-rate debt includes $200.0 millionDP&L Tax-exempt First Mortgage Bonds, which are variable rate, that have been hedged, per discussion above. See Note 6 – Derivative Instruments and Hedging Activities of Notes to DP&L's Condensed Financial Statements

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$1,370.9 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$555.3 million variable-rate long-term debt outstanding as of June 30, 2017.

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$310.2 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$442.8 million variable-rate long-term debt outstanding as of June 30, 2017.

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 in order to mitigate credit risk.

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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, 2016 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
	Six months ended		Six months ended
	June 30,		June 30,
	2017	2016	2017	2016
Electric Sales (millions of kWh)	7,421	7,944	7,225	7,656
Billed electric customers (end of period)	519,697	516,931	519,697	516,931

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

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

Our Chief Executive Officer (CEO) and Chief Financial Officer (CFO) are responsible for establishing and maintaining our disclosure controls and procedures. These controls and procedures were designed to ensure that material information relating to us and our subsidiaries is communicated to the CEO and CFO. We evaluated these disclosure controls and procedures as of the end of the period covered by this report with the participation of our CEO and CFO. Based on this evaluation, our CEO and CFO concluded that, as of June 30, 2017, our disclosure controls and procedures were effective 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.

Changes in Internal Controls over Financial Reporting

We are responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Management assessed the effectiveness of our internal control over financial reporting as of June 30, 2017. In making this assessment, management used the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations (“COSO”) in 2013. 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.

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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.

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, 2016 and Form 10-Q for the quarter ended March 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 Forms 10-K and 10-Q, and should be read in conjunction with such Forms 10-K and 10-Q.

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, 2016. As of June 30, 2017, 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.

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Item 5 – Other Information

None

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Item 6 – Exhibits

DPL Inc.	DP&L	Exhibit Number	Exhibit	Location
X	X	2.1	Asset Purchase Agreement dated April 21, 2017, by and among Dynegy Zimmer, LLC, Dynegy Miami Fort, LLC, AES Ohio Generation, LLC and The Dayton Power and Light Company	Exhibit 2.1 to Report on Form 8-K filed on April 24, 2017 (File No. 1-09052)
X		31(a)	Certification of Chief Executive Officer 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 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 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 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 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 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 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 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.

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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:	August 7, 2017	/s/ Kenneth J. Zagzebski
		Kenneth J. Zagzebski
		President and Chief Executive Officer
		(principal executive officer)
	August 7, 2017	/s/ Craig L. Jackson
		Craig L. Jackson
		Chief Financial Officer
		(principal financial officer)
	August 7, 2017	/s/ Kurt A. Tornquist
		Kurt A. Tornquist
		Controller
		(principal accounting officer)

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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:	August 7, 2017	/s/ Thomas A. Raga
		Thomas A. Raga
		President and Chief Executive Officer
		(principal executive officer)
	August 7, 2017	/s/ Craig L. Jackson
		Craig L. Jackson
		Chief Financial Officer
		(principal financial officer)
	August 7, 2017	/s/ Kurt A. Tornquist
		Kurt A. Tornquist
		Controller
		(principal accounting officer)

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EX-31.A

Exhibit 31(a)

CERTIFICATIONS

I, Kenneth J. Zagzebski, 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: August 7, 2017

/s/ Kenneth J. Zagzebski

Kenneth J. Zagzebski

President and Chief Executive Officer

EX-31.B

Exhibit 31(b)

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: August 7, 2017

/s/ Craig L. Jackson

Craig L. Jackson

Chief Financial Officer

EX-31.C

 Exhibit 31(c)

CERTIFICATIONS

I, Thomas A. Raga, 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: August 7, 2017

/s/ Thomas A. Raga

Thomas A. Raga

President and Chief Executive Officer

EX-31.D

Exhibit 31(d)

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: August 7, 2017

/s/ Craig L. Jackson

Craig L. Jackson

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 June 30, 2017, 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/ Kenneth J. Zagzebski

Kenneth J. Zagzebski

President and Chief Executive Officer

Date: August 7, 2017

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 June 30, 2017, 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

Chief Financial Officer

Date: August 7, 2017

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 June 30, 2017, 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/ Thomas A. Raga

Thomas A. Raga

President and Chief Executive Officer

Date: August 7, 2017

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 June 30, 2017, 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

Chief Financial Officer

Date: August 7, 2017

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	6 Months Ended
	Jun. 30, 2017	Aug. 07, 2017
Entity Registrant Name	DPL INC
Entity Central Index Key	0000787250
Document Type	10-Q
Document Period End Date	Jun. 30, 2017
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		1
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q2
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		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Revenues	$ 298.1	$ 328.3	$ 622.0	$ 692.3
Cost of revenues:
Fuel	54.0	60.2	108.1	127.1
Purchased power	77.4	96.9	179.4	218.8
Total cost of revenues	131.4	157.1	287.5	345.9
Gross margin	166.7	171.2	334.5	346.4
Operating expenses:
Operation and maintenance	82.1	77.2	168.4	165.7
Depreciation and amortization	26.5	36.0	54.5	69.4
General taxes	24.0	21.6	48.2	42.6
Impairment of Long-Lived Assets Held-for-use	0.0	235.5	66.4	235.5
Other	(3.2)	0.0	16.2	0.1
Other Operating Income (Expense), Net	0.3		(0.9)	0.0
Total operating expenses	129.7	370.3	352.8	513.3
Operating income / (loss)	37.0	(199.1)	(18.3)	(166.9)
Other income / (expense), net
Investment income	0.1	0.3	0.1	0.2
Interest expense	(27.4)	(26.0)	(54.3)	(52.3)
Charge for early retirement of debt	(0.3)	0.0	(0.3)	(2.6)
Other deductions	(0.6)	(0.3)	(1.6)	(0.7)
Total other expense	(28.2)	(26.0)	(56.1)	(55.4)
Income / (loss) from continuing operations before income tax	8.8	(225.1)	(74.4)	(222.3)
Income tax expense / (benefit) from continuing operations	8.3	(88.3)	(23.2)	(87.7)
Net income / (loss) from continuing operations	0.5	(136.8)	(51.2)	(134.6)
Loss from discontinued operations	0.0	0.0	0.0	(0.7)
Gain from disposal of discontinued operations	0.0	0.0	0.0	49.2
Income tax expense for discontinued operations	0.0	0.0	0.0	18.9
Net income from discontinued operations	0.0	0.0	0.0	29.6
Net income / (loss)	0.5	(136.8)	(51.2)	(105.0)
THE DAYTON POWER AND LIGHT COMPANY [Member]
Revenues	284.1	313.7	595.2	662.9
Cost of revenues:
Fuel	49.9	55.6	100.0	118.5
Purchased power	76.4	96.7	177.2	218.0
Total cost of revenues	126.3	152.3	277.2	336.5
Gross margin	157.8	161.4	318.0	326.4
Operating expenses:
Operation and maintenance	80.9	76.4	163.5	162.5
Depreciation and amortization	22.0	36.8	45.5	71.1
General taxes	23.6	21.1	47.2	41.6
Impairment of Long-Lived Assets Held-for-use	0.0	857.1	66.3	857.1
Gain on termination of contract	0.0	0.0	0.0	(27.7)
Other	(3.2)	0.1	16.2	0.2
Total operating expenses	123.3	991.5	338.7	1,104.8
Operating income / (loss)	34.5	(830.1)	(20.7)	(778.4)
Other income / (expense), net
Investment income	0.1	0.3	0.1	0.2
Interest expense	(7.8)	(5.4)	(15.4)	(10.7)
Charge for early retirement of debt	(0.1)	0.0	(0.1)	0.0
Other deductions	(0.4)	(0.1)	(1.3)	(0.3)
Total other expense	(8.2)	(5.2)	(16.7)	(10.8)
Income / (loss) from continuing operations before income tax	26.3	(835.3)	(37.4)	(789.2)
Income tax expense / (benefit) from continuing operations	10.2	(303.7)	(11.7)	(291.3)
Net income / (loss)	16.1	(531.6)	(25.7)	(497.9)
Dividends on preferred stock	0.0	0.2	0.0	0.4
Income / (loss) attributable to common stock	$ 16.1	$ (531.8)	$ (25.7)	$ (498.3)

XML

Condensed Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Net income	$ 0.5	$ (136.8)	$ (51.2)	$ (105.0)
Available-for-sale securities activity:
Change in fair value of available-for-sale securities, net of income tax	0.1	(0.1)	0.3	0.1
Reclassification to earnings, net of income tax	0.0	0.1	(0.1)	0.0
Total change in fair value of available-for-sale securities	0.1	0.0	0.2	0.1
Derivative activity:
Change in derivative fair value, net of income tax	1.1	(8.5)	6.1	13.0
Reclassification of earnings, net of income tax	(0.2)	(10.8)	1.0	(19.0)
Total change in fair value of derivatives	0.9	(19.3)	7.1	(6.0)
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax	0.0	0.0	(0.3)	0.0
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), Net of Tax	0.0	0.0	(1.2)	0.0
Pension and postretirement activity:
Reclassification to earnings, net of income tax	0.1	0.1	0.9	0.0
Total change in unfunded pension obligation	0.1	0.1	(0.6)	0.0
Other comprehensive loss	1.1	(19.2)	6.7	(5.9)
Net comprehensive income / (loss)	1.6	(156.0)	(44.5)	(110.9)
THE DAYTON POWER AND LIGHT COMPANY [Member]
Net income	16.1	(531.6)	(25.7)	(497.9)
Available-for-sale securities activity:
Change in fair value of available-for-sale securities, net of income tax	0.1	(0.1)	0.3	0.1
Reclassification to earnings, net of income tax	0.0	0.1	(0.1)	0.0
Total change in fair value of available-for-sale securities	0.1	0.0	0.2	0.1
Derivative activity:
Change in derivative fair value, net of income tax	1.1	(8.5)	6.2	13.0
Reclassification of earnings, net of income tax	(0.2)	(10.8)	0.9	(19.2)
Total change in fair value of derivatives	0.9	(19.3)	7.1	(6.2)
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax	0.0	0.0	(1.1)	0.0
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), Net of Tax	0.0	0.0	(0.5)	0.0
Pension and postretirement activity:
Reclassification to earnings, net of income tax	0.7	0.7	3.2	1.0
Total change in unfunded pension obligation	0.7	0.7	1.6	1.0
Other comprehensive loss	1.7	(18.6)	8.9	(5.1)
Net comprehensive income / (loss)	$ 17.8	$ (550.2)	$ (16.8)	$ (503.0)

XML

Condensed Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Income tax (expense)/benefit on unrealized gains (losses) related to available-for-sale securities	$ 0.0	$ 0.0	$ 0.0	$ (0.1)
Income tax (expense) benefit on reclassification to earnings	0.0	0.0	0.0	0.0
Income tax (expense)/benefit on unrealized gains (losses) related to derivative activity	(0.6)	4.7	(3.4)	7.1
Income tax (expense)/benefit on reclassification of earnings related to derivative activity	0.0	5.9	(0.5)	10.7
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), Tax	0.0	0.0	0.2	0.0
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Tax	0.0	0.0	0.7	0.0
Income tax (expense)/benefit on reclassification of earnings related to pension and postretirement activity	0.0	0.0	(0.5)	(0.2)
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	0.0	(0.1)
Income tax (expense) benefit on reclassification to earnings	0.0	0.0	0.0	0.0
Income tax (expense)/benefit on unrealized gains (losses) related to derivative activity	(0.6)	4.7	(3.4)	(7.0)
Income tax (expense)/benefit on reclassification of earnings related to derivative activity	0.0	5.9	(0.5)	10.7
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), Tax	0.0	0.0	0.6	0.0
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Tax	0.0	0.0	0.2	0.0
Income tax (expense)/benefit on reclassification of earnings related to pension and postretirement activity	$ (0.3)	$ (0.4)	$ (1.6)	$ (1.2)

XML

Condensed Consolidated Balance Sheets - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 34.1	$ 54.6
Restricted cash	1.5	29.0
Accounts receivable, net	99.6	135.1
Inventories	29.3	77.2
Taxes applicable to subsequent years	41.0	81.0
Regulatory assets, current	4.3	0.1
Other prepayments and current assets	29.2	31.8
Assets Held-for-sale, Not Part of Disposal Group, Current	68.6	0.0
Total current assets	307.6	408.8
Property, plant & equipment:
Property, plant & equipment	1,953.4	1,985.6
Less: Accumulated depreciation and amortization	(357.1)	(334.8)
Property, plant and equipment, net of depreciation	1,596.3	1,650.8
Construction work in process	63.3	116.4
Total net property, plant & equipment	1,659.6	1,767.2
Other non-current assets:
Regulatory assets, non-current	209.5	203.9
Intangible assets, net of amortization	19.0	22.7
Other deferred assets	14.7	16.6
Total other non-current assets	243.2	243.2
Total assets	2,210.4	2,419.2
Current liabilities:
Current portion of long-term debt	50.9	29.7
Accounts payable	57.4	113.9
Accrued taxes	154.9	185.1
Accrued interest	17.7	17.7
Security deposits	16.9	15.2
Regulatory liabilities, current	15.0	33.7
Insurance and claims costs	5.4	5.4
Other current liabilities	34.3	50.2
Liabilities Held for Sale, Current	23.2	0.0
Total current liabilities	375.7	450.9
Non-current liabilities:
Long-term debt	1,786.7	1,828.7
Deferred taxes	257.4	252.4
Taxes payable	42.1	84.6
Regulatory liabilities, non-current	133.1	130.4
Pension, retiree and other benefits	101.8	101.6
Asset Retirement Obligations, Noncurrent	131.7	138.8
Other deferred credits	14.0	19.4
Total non-current liabilities	2,466.8	2,555.9
Commitments and contingencies
Common shareholder's equity:
Common stock	0.0	0.0
Other paid-in capital	2,233.0	2,233.0
Accumulated other comprehensive income	7.0	0.3
Retained earnings/ (deficit)	(2,872.1)	(2,820.9)
Total common shareholder's equity	(632.1)	(587.6)
Total liabilities and shareholder's equity	2,210.4	2,419.2
THE DAYTON POWER AND LIGHT COMPANY [Member]
Current assets:
Cash and cash equivalents	6.1	1.6
Restricted cash	1.5	29.0
Accounts receivable, net	95.1	134.6
Inventories	27.7	75.8
Taxes applicable to subsequent years	40.1	79.2
Regulatory assets, current	4.3	0.1
Other prepayments and current assets	28.6	32.4
Assets Held-for-sale, Not Part of Disposal Group, Current	68.6	0.0
Total current assets	272.0	352.7
Property, plant & equipment:
Property, plant & equipment	2,331.7	2,398.6
Less: Accumulated depreciation and amortization	(1,048.3)	(1,047.9)
Property, plant and equipment, net of depreciation	1,283.4	1,350.7
Construction work in process	51.1	89.9
Total net property, plant & equipment	1,334.5	1,440.6
Other non-current assets:
Regulatory assets, non-current	209.5	203.9
Intangible assets, net of amortization	19.3	23.0
Other deferred assets	13.3	14.9
Total other non-current assets	242.1	241.8
Total assets	1,848.6	2,035.1
Current liabilities:
Current portion of long-term debt	26.4	4.7
Short-term debt	0.0	5.0
Accounts payable	54.9	110.5
Accrued taxes	34.0	75.7
Accrued interest	2.1	2.1
Security deposits	16.9	15.2
Regulatory liabilities, current	15.0	33.7
Other current liabilities	33.0	48.3
Liabilities Held for Sale, Current	22.2	0.0
Total current liabilities	204.5	295.2
Non-current liabilities:
Long-term debt	713.5	744.7
Deferred taxes	157.5	146.3
Taxes payable	42.5	84.1
Regulatory liabilities, non-current	133.1	130.4
Pension, retiree and other benefits	101.8	101.6
Asset Retirement Obligations, Noncurrent	129.9	135.2
Unamortized investment tax credit	16.6	17.7
Other deferred credits	12.6	17.6
Total non-current liabilities	1,307.5	1,377.6
Commitments and contingencies
Common shareholder's equity:
Common stock	0.4	0.4
Other paid-in capital	801.8	810.7
Accumulated other comprehensive income	(33.6)	(42.5)
Retained earnings/ (deficit)	(432.0)	(406.3)
Total common shareholder's equity	336.6	362.3
Total liabilities and shareholder's equity	$ 1,848.6	$ 2,035.1

XML

Condensed Consolidated Balance Sheets (Parenthetical) - $ / shares	Jun. 30, 2017	Dec. 31, 2016
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
Common stock, shares outstanding	41,172,173
Common stock, par value (in USD per share)	$ 0.01	$ 0.01

XML

Condensed Consolidated Statements of Cash Flows - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
Cash flows from operating activities:
Net income	$ (51.2)	$ (105.0)
Adjustments to reconcile net income / (loss) to net cash from operating activities:
Depreciation and amortization	54.5	69.4
Charge for early retirement of debt	0.3	2.6
Deferred income taxes	(1.8)	(95.9)
Impairment of Long-Lived Assets Held-for-use	66.4	235.5
Loss on asset disposal	0.0	(49.2)
Gain (Loss) on Sale of Assets and Asset Impairment Charges	16.2	0.1
Changes in certain assets and liabilities:
Accounts receivable	22.4	52.7
Inventories	7.7	21.6
Prepaid taxes	0.0	0.2
Taxes applicable to subsequent years	40.0	41.7
Deferred regulatory costs, net	(9.1)	8.0
Accounts payable	(38.4)	(11.7)
Accrued taxes payable	(65.3)	(25.7)
Accrued interest payable	(0.1)	(0.8)
Security deposits	1.7	0.0
Increase (Decrease) Deferred Investment Tax Credit	(0.2)	(0.2)
Increase (Decrease) in Self Insurance Reserve	(0.1)	(0.4)
Increase (Decrease) in Pension and Postretirement Obligations	2.0	(4.2)
Other	(4.8)	(6.3)
Net cash provided by operating activities	40.2	132.4
Cash flows from investing activities:
Capital expenditures	(66.4)	(79.1)
Proceeds from sale of business	0.0	75.5
Insurance proceeds	0.9	3.2
Purchase of intangible assets	(0.1)	(0.2)
Increase / (decrease) in restricted cash	27.5	(16.0)
Other investing activities, net	0.2	0.7
Net cash provided by / (used in) investing activities	(37.9)	(15.9)
Cash flows from financing activities:
Retirement of long-term debt	(22.8)	(75.4)
Proceeds from (Payments for) Other Financing Activities	0.0	(0.1)
Net cash provided by / (used in) financing activities	(22.8)	(75.5)
Cash and cash equivalents:
Net change	(20.5)	41.0
Balance at beginning of period	54.6	32.4
Cash and cash equivalents at end of period	34.1	73.4
Supplemental cash flow information:
Interest paid, net of amounts capitalized	51.8	51.1
Proceeds from Income Tax Refunds	0.0	0.1
Non-cash financing and investing activities:
Accruals for capital expenditures	9.9	8.3
THE DAYTON POWER AND LIGHT COMPANY [Member]
Adjustments to Additional Paid in Capital, Dividends in Excess of Retained Earnings	(9.0)	0.0
Cash flows from operating activities:
Net income	(25.7)	(497.9)
Adjustments to reconcile net income / (loss) to net cash from operating activities:
Depreciation and amortization	45.5	71.1
Charge for early retirement of debt	0.1	0.0
Deferred income taxes	3.2	(308.7)
Impairment of Long-Lived Assets Held-for-use	66.3	857.1
Gain (Loss) on Sale of Assets and Asset Impairment Charges	16.2	0.2
Changes in certain assets and liabilities:
Accounts receivable	26.3	20.5
Inventories	8.0	21.6
Prepaid taxes	0.0	2.7
Taxes applicable to subsequent years	39.1	40.7
Deferred regulatory costs, net	(9.1)	8.0
Accounts payable	(38.0)	(13.8)
Accrued taxes payable	(75.7)	(43.3)
Accrued interest payable	(0.1)	0.2
Security deposits	1.7	0.0
Increase (Decrease) in Pension and Postretirement Obligations	2.0	(4.2)
Other	(2.3)	5.3
Net cash provided by operating activities	57.5	159.5
Cash flows from investing activities:
Capital expenditures	(57.6)	(71.8)
Insurance proceeds	1.3	3.4
Purchase of intangible assets	(0.1)	(0.3)
Increase / (decrease) in restricted cash	27.5	(16.1)
Other investing activities, net	0.2	0.8
Net cash provided by / (used in) investing activities	(28.7)	(84.0)
Cash flows from financing activities:
Retirement of long-term debt	(10.3)	0.0
Issuance of short-term debt - related party	30.0	5.0
Repayment of short-term debt - related party	(35.0)	(40.0)
Proceeds from (Payments for) Other Financing Activities	0.0	(0.1)
Dividends paid on preferred stock	0.0	(0.4)
Net cash provided by / (used in) financing activities	(24.3)	(35.5)
Cash and cash equivalents:
Net change	4.5	40.0
Balance at beginning of period	1.6	5.4
Cash and cash equivalents at end of period	6.1	45.4
Supplemental cash flow information:
Interest paid, net of amounts capitalized	13.6	8.0
Non-cash financing and investing activities:
Accruals for capital expenditures	$ 9.1	$ 8.3

XML

Overview and Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 2017

Significant Accounting Policies [Line Items]

Overview and Summary of Significant Accounting Policies

Overview and Summary of Significant Accounting Policies

Description of Business

DPL is a diversified regional energy company organized in 1985 under the laws of Ohio. DPL has two reportable segments: the Transmission and Distribution (T&D) segment and the Generation segment. See Note 11 – 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 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 520,000 customers located in West Central Ohio. Additionally, DP&L procures retail SSO electric service on behalf of residential, commercial, industrial and governmental customers in a6,000square mile area of West Central Ohio. DP&L owns undivided interests in multiple coal-fired and peaking electric generating facilities as well as numerous transmission facilities. DP&L sources 100% of the generation for its SSO customers through a competitive bid process. Principal industries located in DP&L’s service territory include automotive, food processing, paper, plastic, manufacturing and defense. DP&L's distribution sales reflect the general economic conditions, seasonal weather patterns, retail competition in our service territory and the market price of electricity. DP&L sells all of its energy and capacity into the wholesale market.

DPL’s other significant subsidiaries include AES Ohio Generation, which owns and operates peaking generating facilities from which it sells all of its energy and capacity into the wholesale market, and MVIC, our captive insurance company that provides insurance services to DPL and our subsidiaries. DPL owns all of the common stock of its subsidiaries.

DPL also has a wholly-owned business trust, DPL Capital Trust II, formed for the purpose of issuing trust capital securities to investors.

DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators while its generation business is deemed competitive under Ohio law. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates, and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs.

DPL and its subsidiaries employed 1,115 people as of June 30, 2017, of which 1,106 were employed by DP&L. Approximately 60% of all DPL employees are under a collective bargaining agreement that expires on October 31, 2017.

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. DP&L has undivided ownership interests in five coal-fired generating facilities, various peaking 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, 2016.

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 June 30, 2017; our results of operations for the three and six months ended June 30, 2017 and 2016 and our cash flows for the six months ended June 30, 2017 and 2016. 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 and six months ended June 30, 2017 may not be indicative of our results that will be realized for the full year ending December 31, 2017.

The preparation of financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the revenues and expenses of the periods reported. Actual results could differ from these estimates. Significant items subject to such estimates and judgments include: the carrying value of property, plant and equipment; unbilled revenues; the valuation of derivative instruments; the valuation of insurance and claims liabilities; the valuation of allowances for receivables and deferred income taxes; regulatory assets and liabilities; 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

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 June 30, 2017 and 2016 were $11.4 million and $11.6 million, respectively. The amounts of such taxes collected for the six months ended June 30, 2017 and 2016 were $23.9 million and $24.5 million, respectively.

New Accounting Pronouncements

The following table provides a brief description of recent accounting pronouncements that could have a material impact on our consolidated financial statements:

Accounting Standard	Description	Date of Adoption	Effect on the financial statements upon adoption
New Accounting Standards Adopted
2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting	The standard simplifies the following aspects of accounting for share-based payments awards: accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, statutory tax withholding requirements, classification of awards as either equity or liabilities and classification of employee taxes paid on statement of cash flows when an employer withholds shares for tax-withholding purposes. Transition method: The recognition of excess tax benefits and tax deficiencies arising from vesting or settlement were applied retrospectively. The elimination of the requirement that excess tax benefits be realized before they are recognized was adopted on a modified retrospective basis with a cumulative adjustment to the opening balance sheet.	January 1, 2017.	The primary effect of adoption was the recognition of excess tax benefits in our provision for income taxes in the period when the awards vest or are settled, rather than in paid-in-capital in the period when the excess tax benefits are realized. We will continue to estimate the number of awards that are expected to vest in our determination of the related periodic compensation cost. The adoption of this standard did not have a material impact on the consolidated financial statements.

Accounting Standard	Description	Date of Adoption	Effect on the financial statements upon adoption
New Accounting Standards Issued But Not Yet Effective
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.
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. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business	This standard provides guidance to assist the entities with evaluating when a set of transferred assets and activities is a business. Transition method: prospective.	January 1, 2018. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2016-18, Statement of Cash Flows (Topic 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. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory	This standard requires that an entity recognizes the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. Transition method: modified retrospective.	January 1, 2018. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
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, Leases (Topic 842)	The standard creates Topic 842, Leases which supersedes Topic 840, Leases, and introduces a lessee model that brings substantially all leases onto the balance sheet while retaining most of the principles of the existing lessor model in U.S. GAAP and aligning many of those principles with ASC 606, Revenue from Contracts with Customers. Transition method: modified retrospective approach with certain practical expedients.	January 1, 2019. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements. We intend to adopt the standard as of January 1, 2019.
2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-05 Revenue from Contracts with Customers (Topic 606)	See discussion of the ASUs below.	January 1, 2018.	We will adopt the standard on January 1, 2018; see below for the evaluation of the impact of its adoption on the consolidated financial statements.

ASU 2014-09 and its subsequent corresponding updates provide the principles an entity must apply to measure and recognize revenue. The core principle is that an entity shall recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Amendments to the standard were issued that provide further clarification of the principle and to provide certain transition expedients. The standard will replace most existing revenue recognition guidance in GAAP, including the guidance on recognizing other income upon the sale or transfer of non-financial assets (including in-substance real estate).

The standard requires retrospective application and allows either a full retrospective adoption in which all of the periods are presented under the new standard or a modified retrospective approach in which the cumulative effect of initially applying the guidance is recognized at the date of initial application. We are currently working toward adopting the standard using the full retrospective method. However, we will continue to assess this conclusion which is dependent on the final impact to the financial statements.

In 2016, we established a cross-functional implementation team and are in the process of evaluating changes to our business processes, systems and controls to support recognition and disclosure under the new standard. At this time, we do not expect any significant impact on our financial systems or a material change to controls as a result of the implementation of the new revenue recognition standard.

We are currently evaluating certain contracts along with our tariff revenue, capacity agreements with PJM and wholesale agreements with PJM. We expect additional contracts to be executed during 2017 that will require assessment under the new standard. Through this assessment, we have identified certain key issues that we are continuing to evaluate in order to complete our assessment of the full population of contracts and be able to assess the overall impact to the financial statements. These issues include: the application of the practical expedient for measuring progress toward satisfaction of a performance obligation, when variable quantities would be considered variable consideration versus an option to acquire additional goods and services, and how to measure progress toward completion for a performance obligation that is a bundle. We are continuing to work with various non-authoritative industry groups, and monitoring the FASB and Transition Resource Group activity, as we finalize our accounting policy on these and other industry specific interpretative issues which is expected in 2017.

THE DAYTON POWER AND LIGHT COMPANY [Member]

Significant Accounting Policies [Line Items]

Overview and Summary of Significant Accounting Policies

Overview and Summary of Significant Accounting Policies

Description of Business

DP&L is a public utility incorporated in 1911 under the laws of Ohio. Beginning in 2001, Ohio law gave Ohio consumers the right to choose the electric generation supplier from whom they purchase retail generation service; however, retail transmission and distribution services are still regulated. DP&L has the exclusive right to provide such transmission and distribution services to approximately 520,000 customers located in West Central Ohio. Additionally, DP&L procures retail SSO electric service on behalf of residential, commercial, industrial and governmental customers in a6,000square mile area of West Central Ohio. DP&L owns undivided interests in multiple coal-fired and peaking electric generating facilities as well as numerous transmission facilities. DP&L sources 100% of the generation for its SSO customers through a competitive bid process. Principal industries located in DP&L’s service territory include automotive, food processing, paper, plastic, manufacturing and defense. DP&L's distribution sales reflect the general economic conditions, seasonal weather patterns, retail competition in our service territory and the market price of electricity. DP&L sells all of its energy and capacity into the wholesale market.DP&L is a subsidiary of DPL.

DP&L has two reportable segments: the Transmission and Distribution (T&D) segment and the Generation segment. See Note 12 – Business Segments for more information relating to these reportable segments.

DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators while its generation business is deemed competitive under Ohio law. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates, and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs.

DP&L employed 1,106 people as of June 30, 2017. Approximately 61% of all employees are under a collective bargaining agreement which expires on October 31, 2017.

Financial Statement Presentation

DP&L does not have any subsidiaries. DP&L has undivided ownership interests in five coal-fired generating facilities, various peaking 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 Statements of Operations.

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, 2016.

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 June 30, 2017; our results of operations for the three and six months ended June 30, 2017 and 2016 and our cash flows for the six months ended June 30, 2017 and 2016. 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 and six months ended June 30, 2017 may not be indicative of our results that will be realized for the full year ending December 31, 2017.

The preparation of financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the revenues and expenses of the periods reported. Actual results could differ from these estimates. Significant items subject to such estimates and judgments include: the carrying value of property, plant and equipment; unbilled revenues; the valuation of derivative instruments; the valuation of insurance and claims liabilities; the valuation of allowances for receivables and deferred income taxes; regulatory assets and liabilities; 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

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 June 30, 2017 and 2016 were $11.4 million and $11.6 million, respectively. The amounts of such taxes collected for the six months ended June 30, 2017 and 2016 were $23.9 million and $24.5 million, respectively.

New Accounting Pronouncements

The following table provides a brief description of recent accounting pronouncements that could have a material impact on our financial statements:

Accounting Standard	Description	Date of Adoption	Effect on the financial statements upon adoption
New Accounting Standards Adopted
2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting	The standard simplifies the following aspects of accounting for share-based payments awards: accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, statutory tax withholding requirements, classification of awards as either equity or liabilities and classification of employee taxes paid on statement of cash flows when an employer withholds shares for tax-withholding purposes. Transition method: The recognition of excess tax benefits and tax deficiencies arising from vesting or settlement were applied retrospectively. The elimination of the requirement that excess tax benefits be realized before they are recognized was adopted on a modified retrospective basis with a cumulative adjustment to the opening balance sheet.	January 1, 2017.	The primary effect of adoption was the recognition of excess tax benefits in our provision for income taxes in the period when the awards vest or are settled, rather than in paid-in-capital in the period when the excess tax benefits are realized. We will continue to estimate the number of awards that are expected to vest in our determination of the related periodic compensation cost. The adoption of this standard did not have a material impact on the financial statements.
New Accounting Standards Issued But Not Yet Effective
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.
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. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements.
2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business	This standard provides guidance to assist the entities with evaluating when a set of transferred assets and activities is a business. Transition method: prospective.	January 1, 2018. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements.

Accounting Standard	Description	Date of Adoption	Effect on the financial statements upon adoption
2016-18, 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. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements.
2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory	This standard requires that an entity recognizes the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. Transition method: modified retrospective.	January 1, 2018. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements.
2016-13, 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, Leases (Topic 842)	The standard creates Topic 842, Leases which supersedes Topic 840, Leases, and introduces a lessee model that brings substantially all leases onto the balance sheet while retaining most of the principles of the existing lessor model in U.S. GAAP and aligning many of those principles with ASC 606, Revenue from Contracts with Customers. Transition method: modified retrospective approach with certain practical expedients.	January 1, 2019. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements. We intend to adopt the standard as of January 1, 2019.
2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-05 Revenue from Contracts with Customers (Topic 606)	See discussion of the ASUs below.	January 1, 2018.	We will adopt the standard on January 1, 2018; see below for the evaluation of the impact of its adoption on the financial statements.

ASU 2014-09 and its subsequent corresponding updates provide the principles an entity must apply to measure and recognize revenue. The core principle is that an entity shall recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Amendments to the standard were issued that provide further clarification of the principle and to provide certain transition expedients. The standard will replace most existing revenue recognition guidance in GAAP, including the guidance on recognizing other income upon the sale or transfer of non-financial assets (including in-substance real estate).

The standard requires retrospective application and allows either a full retrospective adoption in which all of the periods are presented under the new standard or a modified retrospective approach in which the cumulative effect of initially applying the guidance is recognized at the date of initial application. We are currently working toward adopting the standard using the full retrospective method. However, we will continue to assess this conclusion which is dependent on the final impact to the financial statements.

In 2016, we established a cross-functional implementation team and are in the process of evaluating changes to our business processes, systems and controls to support recognition and disclosure under the new standard. At this time, we do not expect any significant impact on our financial systems or a material change to controls as a result of the implementation of the new revenue recognition standard.

We are currently evaluating certain contracts along with our tariff revenue, capacity agreements with PJM and wholesale agreements with PJM. We expect additional contracts to be executed during 2017 that will require assessment under the new standard. Through this assessment, we have identified certain key issues that we are continuing to evaluate in order to complete our assessment of the full population of contracts and be able to assess the overall impact to the financial statements. These issues include: the application of the practical expedient for measuring progress toward satisfaction of a performance obligation, when variable quantities would be considered variable consideration versus an option to acquire additional goods and services, and how to measure progress toward completion for a performance obligation that is a bundle. We are continuing to work with various non-authoritative industry groups, and monitoring the FASB and Transition Resource Group activity, as we finalize our accounting policy on these and other industry specific interpretative issues which is expected in 2017.

XML

Supplemental Financial Information

6 Months Ended

Jun. 30, 2017

Supplemental Financial Information [Line Items]

Supplemental Financial Information

Supplemental Financial Information

Accounts receivable and Inventories are as follows at June 30, 2017 and December 31, 2016:

	June 30,			December 31,
$ in millions	2017			2016
Accounts receivable, net:
Unbilled revenue	$	15.5		$	43.0
Customer receivables	62.1			73.9
Amounts due from partners in jointly owned plants	3.6			12.7
Other	19.4			6.7
Provision for uncollectible accounts	(1.0		)	(1.2		)
Total accounts receivable, net	$	99.6		$	135.1
Inventories, at average cost:
Fuel and limestone	$	17.6		$	38.9
Plant materials and supplies	10.4			36.6
Other	1.3			1.7
Total inventories, at average cost	$	29.3		$	77.2

Accumulated Other Comprehensive Income / (Loss)

The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the three and six months ended June 30, 2017 and 2016 are as follows:

Details about Accumulated Other Comprehensive Income / (Loss) components	Affected line item in the Condensed Consolidated Statements of Operations	Three months ended						Six months ended
		June 30,						June 30,
$ in millions		2017			2016			2017			2016
Gains and losses on Available-for-sale securities activity (Note 5):
	Other income	$	—		$	0.1		$	(0.1	)	$	—
Gains and losses on cash flow hedges (Note 6):
	Interest expense	(0.3		)	(0.3		)	(0.5		)	(0.5		)
	Revenue	0.1			(20.1		)	(1.3		)	(37.3		)
	Purchased power	—			3.7			3.3			8.1
	Total before income taxes	(0.2		)	(16.7		)	1.5			(29.7		)
	Tax expense / (benefit)	—			5.9			(0.5		)	10.7
	Net of income taxes	(0.2		)	(10.8		)	1.0			(19.0		)
Amortization of defined benefit pension items (Note 9):
	Operation and maintenance	0.1			0.1			1.4			0.2
	Tax benefit	—			—			(0.5		)	(0.2		)
	Net of income taxes	0.1			0.1			0.9			—
Total reclassifications for the period, net of income taxes		$	(0.1	)	$	(10.6	)	$	1.8		$	(19.0	)

The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the six months endedJune 30, 2017 are as follows:

$ in millions	Gains / (losses) on available-for-sale securities			Gains / (losses) on cash flow hedges		Change in unfunded pension obligation			Total
Balance January 1, 2017	$	0.6		$	13.1	$	(13.4	)	$	0.3
Other comprehensive income / (loss) before reclassifications	0.3			6.1		(1.5		)	4.9
Amounts reclassified from accumulated other comprehensive income / (loss)	(0.1		)	1.0		0.9			1.8
Net current period other comprehensive income / (loss)	0.2			7.1		(0.6		)	6.7
Balance June 30, 2017	$	0.8		$	20.2	$	(14.0	)	$	7.0

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 June 30, 2017 and December 31, 2016:

	June 30,			December 31,
$ in millions	2017			2016
Accounts receivable, net:
Unbilled revenue	$	15.5		$	43.0
Customer receivables	55.9			71.2
Amounts due from partners in jointly owned plants	3.6			12.7
Amounts due from affiliates	2.1			2.9
Other	19.0			6.0
Provision for uncollectible accounts	(1.0		)	(1.2		)
Total accounts receivable, net	$	95.1		$	134.6
Inventories, at average cost:
Fuel and limestone	$	17.6		$	38.8
Plant materials and supplies	8.8			35.3
Other	1.3			1.7
Total inventories, at average cost	$	27.7		$	75.8

Accumulated Other Comprehensive Income / (Loss)

The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the three and six months ended June 30, 2017 and 2016 are as follows:

Details about Accumulated Other Comprehensive Income / (Loss) components	Affected line item in the Condensed Statements of Operations	Three months ended						Six months ended
		June 30,						June 30,
$ in millions		2017			2016			2017			2016
Gains and losses on Available-for-sale securities activity (Note 5):
	Other income	$	—		$	0.1		$	(0.1	)	$	—
Gains and losses on cash flow hedges (Note 6):
	Interest expense	(0.3		)	(0.3		)	(0.6		)	(0.6		)
	Revenue	0.1			(20.1		)	(1.3		)	(37.2		)
	Purchased power	—			3.7			3.3			8.1
	Total before income taxes	(0.2		)	(16.7		)	1.4			(29.7		)
	Tax expense / (benefit)	—			5.9			(0.5		)	10.5
	Net of income taxes	(0.2		)	(10.8		)	0.9			(19.2		)
Amortization of defined benefit pension items (Note 9):
	Operation and maintenance	1.0			1.1			4.8			2.2
	Tax benefit	(0.3		)	(0.4		)	(1.6		)	(1.2		)
	Net of income taxes	0.7			0.7			3.2			1.0
Total reclassifications for the period, net of income taxes		$	0.5		$	(10.0	)	$	4.0		$	(18.2	)

The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the six months ended June 30, 2017 are as follows:

$ in millions	Gains / (losses) on available-for-sale securities			Gains / (losses) on cash flow hedges			Change in unfunded pension obligation			Total
Balance January 1, 2017	$	0.7		$	(2.7	)	$	(40.5	)	$	(42.5	)
Other comprehensive income / (loss) before reclassifications	0.3			6.2			(1.6		)	4.9
Amounts reclassified from accumulated other comprehensive income / (loss)	(0.1		)	0.9			3.2			4.0
Net current period other comprehensive income	0.2			7.1			1.6			8.9
Balance June 30, 2017	$	0.9		$	4.4		$	(38.9	)	$	(33.6	)

XML

Regulatory Matters (Notes)

6 Months Ended

Jun. 30, 2017

Schedule of Regulatory Assets and Liabilities [Text Block]

Regulatory Matters

DP&L originally filed its ESP 3 seeking an effective date of January 1, 2017. On October 11, 2016, DP&L amended the application requesting to collect $145.0 million per year for seven years, named the Distribution Modernization Rider ("DMR"). This plan established the terms and conditions for DP&L’s SSO to customers that do not choose a competitive retail electric supplier, and recommended including renewable energy attributes as part of the product that is competitively bid. DP&L sought recovery of approximately $10.5 million of regulatory assets, and proposed a new Distribution Investment Rider to allow DP&L to recover costs associated with future distribution equipment and infrastructure needs. Additionally, the plan established new riders set initially at zero, related to energy reductions from DP&L’s energy efficiency programs, and certain environmental liabilities.

On January 30, 2017, DP&L, in conjunction with various intervening parties, filed a settlement in the ESP 3 case. On March 13, 2017, DP&L, in conjunction with various intervening parties and the staff of the PUCO, filed an amended stipulation in the ESP 3 case, which is subject to PUCO approval. The intervening parties agreed to a six-year settlement that provides a framework for energy rates and defines components which include, but are not limited to, the following:

• Bypassable standard offer energy rates for DP&L’s customers based on competitive bid auctions;

• The establishment of a three-year non-bypassable DMR designed to collect $105.0 million in revenue per year to pay debt obligations at DPL and DP&L and position DP&L to modernize and/or maintain its transmission and distribution infrastructure. With PUCO approval, DP&L has the option of extending the duration of the DMR for an additional two years;

• The establishment of a non-bypassable Distribution Investment Rider, set initially at zero, to recover incremental distribution capital investments;

• The establishment of a Smart Grid Rider, set initially at zero, to recover costs of future grid modernization;

• A commitment by us to separate DP&L’s generation assets from its transmission and distribution assets (if approved by FERC) within 180 days after receipt of a PUCO order;

• A commitment to commence a sale process to sell our ownership interests in the Zimmer, Miami Fort and Conesville coal-fired generation plants; and

• Restrictions on DPL making dividend or tax sharing payments, and various other riders and competitive retail market enhancements.

A hearing was held in April 2017 and a final decision by the PUCO is expected in the third quarter of 2017. There can be no assurance that the amended ESP 3 stipulation will be approved as filed or on a timely basis, and if the Amended ESP 3 stipulation is not approved on a timely basis or if the final ESP provides for terms that are more adverse than those submitted in DP&L's amended stipulation, our results of operations, financial condition and cash flows and DPL's ability to meet long-term obligations, in the periods beyond twelve months from the date of this report, could be materially impacted.

In connection with any sale or closure of our generation plants as contemplated by the ESP 3 settlement or otherwise, DPL and DP&L would expect to incur certain cash and non-cash charges, some or all of which could be material to the business and financial condition of DPL and DP&L.

DP&L’s ESP 2 had been approved by the PUCO for the years 2014 - 2016, and permitted DP&L to collect a non-bypassable service stability rider equal to $110.0 million per year for each of those years and required DP&L to conduct competitive bid auctions to procure generation supply for SSO service. The Ohio Supreme Court in a June 2016 opinion stated that the PUCO’s approval of the ESP was reversed. In view of that reversal, DP&L filed a motion to withdraw its ESP 2 and implement rates consistent with those in effect prior to 2014. The PUCO approved DP&L’s withdrawal of ESP 2 and implementation plans. Those rates will be in effect until rates approved as a result of DP&L’s pending ESP 3 are effective. In February 2017, several parties appealed the PUCO orders that approved both the withdrawal and the implementation plans to the Ohio Supreme Court. Those appeals are pending and the outcome and potential financial impact of those appeals cannot be determined at this time. In July 2017, the Office of the Ohio Consumers Counsel filed a motion with the Ohio Supreme Court seeking to stay collection of the reinstated prior rates while the appeals are pending.

Subsidiaries [Member]

Schedule of Regulatory Assets and Liabilities [Text Block]

Regulatory Matters

DP&L originally filed its ESP 3 seeking an effective date of January 1, 2017. On October 11, 2016, DP&L amended the application requesting to collect $145.0 million per year for seven years, named the Distribution Modernization Rider ("DMR"). This plan established the terms and conditions for DP&L’s SSO to customers that do not choose a competitive retail electric supplier, and recommended including renewable energy attributes as part of the product that is competitively bid. DP&L sought recovery of approximately $10.5 million of regulatory assets, and proposed a new Distribution Investment Rider to allow DP&L to recover costs associated with future distribution equipment and infrastructure needs. Additionally, the plan established new riders set initially at zero, related to energy reductions from DP&L’s energy efficiency programs, and certain environmental liabilities.

On January 30, 2017, DP&L, in conjunction with various intervening parties, filed a settlement in the ESP 3 case. On March 13, 2017, DP&L, in conjunction with various intervening parties and the staff of the PUCO, filed an amended stipulation in the ESP 3 case, which is subject to PUCO approval. The intervening parties agreed to a six-year settlement that provides a framework for energy rates and defines components which include, but are not limited to, the following:

• Bypassable standard offer energy rates for DP&L’s customers based on competitive bid auctions;

• The establishment of a three-year non-bypassable DMR designed to collect $105.0 million in revenue per year to pay debt obligations at DPL and DP&L and position DP&L to modernize and/or maintain its transmission and distribution infrastructure. With PUCO approval, DP&L has the option of extending the duration of the DMR for an additional two years;

• The establishment of a non-bypassable Distribution Investment Rider, set initially at zero, to recover incremental distribution capital investments;

• The establishment of a Smart Grid Rider, set initially at zero, to recover costs of future grid modernization;

• A commitment by us to separate DP&L’s generation assets from its transmission and distribution assets (if approved by FERC) within 180 days after receipt of a PUCO order;

• A commitment to commence a sale process to sell our ownership interests in the Zimmer, Miami Fort and Conesville coal-fired generation plants; and

• Restrictions on DPL making dividend or tax sharing payments, and various other riders and competitive retail market enhancements.

A hearing was held in April 2017 and a final decision by the PUCO is expected in the third quarter of 2017. There can be no assurance that the amended ESP 3 stipulation will be approved as filed or on a timely basis, and if the Amended ESP 3 stipulation is not approved on a timely basis or if the final ESP provides for terms that are more adverse than those submitted in DP&L's amended stipulation, our results of operations, financial condition and cash flows and DPL's ability to meet long-term obligations, in the periods beyond twelve months from the date of this report, could be materially impacted.

In connection with any sale or closure of our generation plants as contemplated by the ESP 3 settlement or otherwise, DPL and DP&L would expect to incur certain cash and non-cash charges, some or all of which could be material to the business and financial condition of DPL and DP&L.

DP&L’s ESP 2 had been approved by the PUCO for the years 2014 - 2016, and permitted DP&L to collect a non-bypassable service stability rider equal to $110.0 million per year for each of those years and required DP&L to conduct competitive bid auctions to procure generation supply for SSO service. The Ohio Supreme Court in a June 2016 opinion stated that the PUCO’s approval of the ESP was reversed. In view of that reversal, DP&L filed a motion to withdraw its ESP 2 and implement rates consistent with those in effect prior to 2014. The PUCO approved DP&L’s withdrawal of ESP 2 and implementation plans. Those rates will be in effect until rates approved as a result of DP&L’s pending ESP 3 are effective. In February 2017, several parties appealed the PUCO orders that approved both the withdrawal and the implementation plans to the Ohio Supreme Court. Those appeals are pending and the outcome and potential financial impact of those appeals cannot be determined at this time. In July 2017, the Office of the Ohio Consumers Counsel filed a motion with the Ohio Supreme Court seeking to stay collection of the reinstated prior rates while the appeals are pending.

XML

Property, Plant and Equipment (Notes)

6 Months Ended

Jun. 30, 2017

Property, Plant and Equipment [Line Items]

Property, Plant and Equipment Disclosure [Text Block]

Property, Plant and Equipment

Coal-fired facilities

DP&L and certain other Ohio utilities have undivided ownership interests in five coal-fired electric generating facilities and numerous transmission facilities. Certain expenses, primarily fuel costs for the generating units, are allocated to the owners based on their energy usage. The remaining expenses, investments in fuel inventory, plant materials and operating supplies, and capital additions are allocated to the owners in accordance with their respective ownership interests. DP&L’s share of the operations of such facilities is included within the corresponding line in the Condensed Consolidated Statements of Operations, and DP&L’s share of the investment in the facilities is included within Total net property, plant and equipment in the Condensed Consolidated Balance Sheets, except for amounts related to Miami Fort and Zimmer, which are classified as Held for Sale, as described below. Each joint owner provides their own financing for their share of the operations and capital expenditures of the jointly-owned station.

DP&L’s undivided ownership interest in such facilities at June 30, 2017, is as follows:

	DP&L Share		DPL Carrying Value
	Ownership (%)	Summer Production Capacity (MW)	Gross Plant In Service ($ in millions)		Accumulated Depreciation ($ in millions)		Construction Work in Process ($ in millions)
Jointly-owned production units
Conesville - Unit 4	16.5	129	$	0.6	$	0.6	$	0.7
Killen - Unit 2	67.0	402	8.4		2.5		—
Miami Fort - Units 7 and 8 (a)	36.0	368	31.2		3.1		5.1
Stuart - Units 2 through 4	35.0	606	0.9		0.9		—
Zimmer - Unit 1 (a)	28.1	371	19.9		14.4		5.3
Transmission (at varying percentages)			43.9		11.7		—
Total		1,876	$	104.9	$	33.2	$	11.1

(a) DP&L has entered into an agreement to sell its interest in these units. See Note 13 – Assets and Liabilities Held For Sale for additional information.

Each of the above generating units has SCR and FGD equipment installed.

On January 10, 2017, a high pressure feedwater heater shell failed on Unit 1 at the J.M. Stuart station. As a result, $6.4 million of net book value was written off, resulting in a $3.2 million loss on disposal, net of accrued insurance recoveries being recorded during the first quarter of 2017. This loss was reversed during the second quarter of 2017 due to additional accrued insurance recoveries. On August 2, 2017, the DP&L Board of Directors approved retiring this unit on or around October 1, 2017 and the co-owners of this unit agreed with DP&L to proceed with this retirement. Accordingly, the 202 MWs of capacity associated with Stuart Unit 1 have been removed from the table above.

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 on or before June 1, 2018, and the co-owners of these facilities agreed with DP&L to proceed with this plan of retirement.

On April 21, 2017, DP&L and AES Ohio Generation entered into an agreement for the sale of DP&L’s undivided interests in Zimmer and Miami Fort for $50.0 million in cash and the assumption of certain liabilities, including environmental liabilities. The purchase price is subject to adjustment at closing based on the amount of certain inventories, pre-paid amounts, employment benefits, insurance premiums, property taxes and other costs. The sale is subject to approval by the FERC and is expected to close in the third quarter of 2017. See Note 13 – Assets and Liabilities Held For Sale for additional 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 Generation AROs

$ in millions
Balance January 1, 2017	$	138.8
Revisions to cash flow and timing estimates	(4.4		)
Accretion expense	2.0
Settlements	—
Reclassified to Liabilities held for sale	(4.7		)
Balance June 30, 2017	$	131.7

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

Coal-fired facilities

DP&L and certain other Ohio utilities have undivided ownership interests in five coal-fired electric generating facilities and numerous transmission facilities. Certain expenses, primarily fuel costs for the generating units, are allocated to the owners based on their energy usage. The remaining expenses, investments in fuel inventory, plant materials and operating supplies, and capital additions are allocated to the owners in accordance with their respective ownership interests. DP&L’s share of the operations of such facilities is included within the corresponding line in the Condensed Statements of Operations, and DP&L’s share of the investment in the facilities is included within Total net property, plant and equipment in the Condensed Balance Sheets, except for amounts related to Miami Fort and Zimmer, which are classified as Held for Sale, as described below. Each joint owner provides their own financing for their share of the operations and capital expenditures of the jointly-owned station.

DP&L’s undivided ownership interest in such facilities at June 30, 2017, is as follows:

	DP&L Share		DP&L Carrying Value
	Ownership %	Summer Production Capacity (MW)	Gross Plant In Service ($ in millions)		Accumulated Depreciation ($ in millions)		Construction Work in Process ($ in millions)
Jointly-owned production units
Conesville - Unit 4	16.5	129	$	0.6	$	0.6	$	0.7
Killen - Unit 2	67.0	402	8.4		2.5		—
Miami Fort - Units 7 and 8 (a)	36.0	368	31.2		3.1		5.1
Stuart - Units 2 through 4	35.0	606	0.9		0.9		—
Zimmer - Unit 1 (a)	28.1	371	19.9		14.4		5.3
Transmission (at varying percentages)			99.3		67.1		—
Total		1,876	$	160.3	$	88.6	$	11.1

(a) DP&L has entered into an agreement to sell its interest in these units. See Note 13 – Assets and Liabilities Held For Sale for additional information.

Each of the above generating units has SCR and FGD equipment installed.

On January 10, 2017, a high pressure feedwater heater shell failed on Unit 1 at the J.M. Stuart station. As a result, $6.4 million of net book value was written off, resulting in a $3.2 million loss on disposal, net of accrued insurance recoveries being recorded during the first quarter of 2017. This loss was reversed during the second quarter of 2017 due to additional accrued insurance recoveries. On August 2, 2017, the DP&L Board of Directors approved retiring this unit on or around October 1, 2017 and the co-owners of this unit agreed with DP&L to proceed with this retirement. Accordingly, the 202 MWs of capacity associated with Stuart Unit 1 have been removed from the table above.

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 on or before June 1, 2018, and the co-owners of these facilities agreed with DP&L to proceed with this plan of retirement.

On April 21, 2017, DP&L and AES Ohio Generation entered into an agreement for the sale of DP&L’s undivided interests in Zimmer and Miami Fort for $50.0 million in cash and the assumption of certain liabilities, including environmental liabilities. The purchase price is subject to adjustment at closing based on the amount of certain inventories, pre-paid amounts, employment benefits, insurance premiums, property taxes and other costs. The sale is subject to approval by the FERC and is expected to close in the third quarter of 2017.

AROs

We recognize AROs in accordance with GAAP which requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time those obligations are incurred. Upon initial recognition of a legal liability, costs are capitalized as part of the related long-lived asset and depreciated over the useful life of the related asset. Our legal obligations are associated with the retirement of our long-lived assets, consisting primarily of river intake and discharge structures, coal unloading facilities, loading docks, ice breakers and ash disposal facilities.

Estimating the amount and timing of future expenditures of this type requires significant judgment. Management routinely updates these estimates as additional information becomes available.

Changes in the Liability for Generation AROs

$ in millions
Balance January 1, 2017	$	135.2
Revisions to cash flow and timing estimates	(4.4		)
Accretion expense	2.8
Settlements	—
Reclassified to Liabilities held for sale	(3.7		)
Balance June 30, 2017	$	129.9

See Note 5 – Fair Value for further discussion on changes to our AROs.

XML

Fair Value

6 Months Ended

Jun. 30, 2017

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 June 30, 2017 and December 31, 2016. Information about the fair value of our derivative instruments can be found in Note 6 – Derivative Instruments and Hedging Activities.

	June 30, 2017				December 31, 2016
$ in millions	Cost		Fair Value		Cost		Fair Value
Assets
Money market funds	$	0.4	$	0.4	$	0.4	$	0.4
Equity securities	2.6		3.9		2.4		3.4
Debt securities	4.2		4.3		4.4		4.4
Hedge funds	0.1		0.1		—		0.1
Real estate	—		—		0.3		0.3
Tangible assets	0.1		0.1		0.1		0.1
Total Assets	$	7.4	$	8.8	$	7.6	$	8.7
	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities
Long-term debt (a)	$	1,837.3	$	1,926.2	$	1,858.0	$	1,907.7

(a) Amounts exclude immaterial capital lease obligations

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.

Long-term debt

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.

Master Trust Assets

DP&L established Master Trusts 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. These assets are primarily comprised of open-ended mutual funds, which are valued using the net asset value per unit. These investments are recorded at fair value within Other deferred assets on the balance sheets and classified as available-for-sale. Any unrealized gains or losses are recorded in AOCI until the securities are sold.

DPL had $1.3 million ($0.9 million after tax) of unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at June 30, 2017 and $1.0 million ($0.6 million after tax) of unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at December 31, 2016.

During the six months endedJune 30, 2017, $0.8 million ($0.5 million after tax) of various investments were sold to facilitate the distribution of benefits and the unrealized gains were reversed into earnings. An immaterial amount of unrealized gains are expected to be reversed to earnings as investments are sold over the next twelve months to facilitate the distribution of benefits.

Fair Value Hierarchy

Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. These inputs are then categorized as:

• Level 1 (quoted prices in active markets for identical assets or liabilities);

• Level 2 (observable inputs such as quoted prices for similar assets or liabilities or quoted prices in markets that are not active); or

• Level 3 (unobservable inputs).

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 six months ended June 30, 2017 or 2016.

The fair value of assets and liabilities at June 30, 2017 and December 31, 2016 and the respective category within the fair value hierarchy for DPL was determined as follows:

Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
$ in millions	Fair value at June 30, 2017		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.4	$	0.4	$	—	$	—
Equity securities	3.9		—		3.9		—
Debt securities	4.3		—		4.3		—
Hedge funds	0.1		—		0.1		—
Tangible assets	0.1		—		0.1		—
Total Master Trust assets	8.8		0.4		8.4		—
Derivative Assets
Forward power contracts	16.4		—		16.4		—
Interest rate hedges	0.9		—		0.9		—
Natural gas	0.3		0.3		—		—
Total Derivative assets	17.6		0.3		17.3		—
Total Assets	$	26.4	$	0.7	$	25.7	$	—
Liabilities
Derivative Liabilities
Interest rate hedges	$	0.2	$	—	$	0.2	$	—
FTRs	0.6		—		—		0.6
Natural gas futures	1.0		1.0		—		—
Forward power contracts	9.8		—		9.8		—
Total Derivative liabilities	11.6		1.0		10.0		0.6
Long-term debt	1,926.3		—		1,908.4		17.9
Total Liabilities	$	1,937.9	$	1.0	$	1,918.4	$	18.5

Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
$ in millions	Fair value at December 31, 2016		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.4	$	0.4	$	—	$	—
Equity securities	3.4		—		3.4		—
Debt securities	4.4		—		4.4		—
Hedge funds	0.1		—		0.1		—
Real estate	0.3		—		0.3		—
Tangible assets	0.1		—		0.1		—
Total Master Trust assets	8.7		0.4		8.3		—
Derivative assets
Forward power contracts	19.5		—		19.5		—
Interest rate hedges	1.2		—		1.2		—
FTRs	0.1		—		—		0.1
Total Derivative assets	20.8		—		20.7		0.1
Total Assets	$	29.5	$	0.4	$	29.0	$	0.1
Liabilities
Derivative liabilities
Interest rate hedges	$	0.7	$	—	$	0.7	$	—
Forward power contracts	28.5		—		26.0		2.5
Total Derivative liabilities	29.2		—		26.7		2.5
Long-term debt	1,907.7		—		1,889.7		18.0
Total Liabilities	$	1,936.9	$	—	$	1,916.4	$	20.5

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 that are in the Master Trust, which are valued using observable prices based on the end of day net asset value 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 89% 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 loan 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. As a result of changes in our estimates of costs to be incurred for our AROs, we decreased our AROs by $4.4 million in the first six months of 2017. AROs for ash ponds, asbestos, ash landfills, river structures and underground storage tanks decreased by a net amount of $2.4 million and increased by a net amount of $2.3 million during the six months ended June 30, 2017 and 2016, respectively. In addition, there was a $4.7 million decrease in the ARO liability during the six months ended June 30, 2017 related to AROs at Miami Fort and Zimmer being reclassified to Liabilities held for sale - current.

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 14 – Fixed-asset Impairments.

A ruling by the Supreme Court of Ohio on June 20, 2016, lower expectation of future capacity revenue resulting from the most recent PJM capacity auction and a higher anticipated level of environmental compliance costs resulting from third party studies were collectively determined to be an impairment indicator for these assets. As a result, we performed a long-lived asset impairment analysis during the second quarter of 2016 and determined that the carrying amount of Killen and certain DP&L peaking generating facilities were not recoverable. See Note 14 – 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:

$ in millions	Carrying		Fair Value						Gross
	Amount (b)		Level 1		Level 2		Level 3		Loss
	Six months ended June 30, 2017
Assets
Long-lived assets (a)
Stuart	$	42.4	$	—	$	—	$	3.3	$	39.1
Killen	$	35.2	$	—	$	—	$	7.9	$	27.3
	Six months ended June 30, 2016
Assets
Long-lived assets (a)
Killen	$	315.1	$	—	$	—	$	84.3	$	230.8
DP&L peaking facilities	$	9.9	$	—	$	—	$	5.2	$	4.7

(a)See Note 14 – Fixed-asset Impairments for further information

(b)Carrying amount at date of valuation

The following summarizes the significant unobservable inputs used in the Level 3 measurement on a non-recurring basis during the six months ended June 30, 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	%
				Weighted-average cost of capital	7	%
Killen	$	7.9	Discounted cash flow	Pre-tax operating margin (through remaining life)	22	%
				Weighted-average cost of capital	7	%

The following summarizes the significant unobservable inputs used in the Level 3 measurement on a non-recurring basis during the six months ended June 30, 2016:

$ in millions	Fair value		Valuation technique	Unobservable input	Weighted average
Long-lived assets held and used:
Killen	$	84.3	Discounted cash flow	Annual revenue growth	-11% to 13% (2%)
				Annual pre-tax operating margin	-50% to 67% (6%)
				Weighted-average cost of capital	11%
DP&L peaking facilities	$	5.2	Discounted cash flow	Annual revenue growth	-22% to 17% (-3%)
				Annual pre-tax operating margin	-29% to 24% (-4%)
				Weighted-average cost of capital	7%

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 June 30, 2017 and December 31, 2016. Information about the fair value of our derivative instruments can be found in Note 6 – Derivative Instruments and Hedging Activities.

	June 30, 2017				December 31, 2016
$ in millions	Cost		Fair Value		Cost		Fair Value
Assets
Money market funds	$	0.4	$	0.4	$	0.4	$	0.4
Equity securities	2.6		3.9		2.4		3.4
Debt securities	4.2		4.3		4.4		4.4
Hedge funds	0.1		0.1		—		0.1
Real estate	—		—		0.3		0.3
Tangible assets	0.1		0.1		0.1		0.1
Total assets	$	7.4	$	8.8	$	7.6	$	8.7
	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities
Long-term debt (a)	$	739.6	$	753.0	$	749.0	$	763.5

(a) Amounts exclude immaterial capital lease obligations

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.

Long-term debt

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.

Master Trust Assets

DP&L established Master Trusts 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. These assets are primarily comprised of open-ended mutual funds, which are valued using the net asset value per unit. These investments are recorded at fair value within Other deferred assets on the balance sheets and classified as available-for-sale. Any unrealized gains or losses are recorded in AOCI until the securities are sold.

DP&L had $1.4 million ($0.9 million after tax) of unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at June 30, 2017 and $1.1 million ($0.7 million after tax) in unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at December 31, 2016.

During the six months endedJune 30, 2017, $0.8 million ($0.5 million after tax) of various investments were sold to facilitate the distribution of benefits and the unrealized gains were reversed into earnings. An immaterial amount of unrealized gains are expected to be reversed to earnings as investments are sold over the next twelve months to facilitate the distribution of benefits.

Fair Value Hierarchy

Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. These inputs are then categorized as:

• Level 1 (quoted prices in active markets for identical assets or liabilities);

• Level 2 (observable inputs such as quoted prices for similar assets or liabilities or quoted prices in markets that are not active); or

• Level 3 (unobservable inputs).

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 six months ended June 30, 2017 or 2016.

The fair value of assets and liabilities at June 30, 2017 and December 31, 2016 and the respective category within the fair value hierarchy for DP&L was determined as follows:

Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
$ in millions	Fair value at June 30, 2017		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.4	$	0.4	$	—	$	—
Equity securities	3.9		—		3.9		—
Debt securities	4.3		—		4.3		—
Hedge funds	0.1		—		0.1		—
Tangible assets	0.1		—		0.1		—
Total Master Trust assets	8.8		0.4		8.4		—
Derivative assets
Natural gas futures	0.3		0.3		—		—
Interest rate hedges	0.9		—		0.9		—
Forward power contracts	16.4		—		16.4		—
Total derivative assets	17.6		0.3		17.3		—
Total assets	$	26.4	$	0.7	$	25.7	$	—
Liabilities
Derivative liabilities
FTRs	$	0.6	$	—	$	—	$	0.6
Interest rate hedges	0.2		—		0.2		—
Natural gas futures	1.0		1.0		—		—
Forward power contracts	9.8		—		9.8		—
Total derivative liabilities	11.6		1.0		10.0		0.6
Long-term debt (a)	753.0		—		735.1		17.9
Total liabilities	$	764.6	$	1.0	$	745.1	$	18.5

(a) Amounts exclude immaterial capital lease obligations

Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
$ in millions	Fair value at December 31, 2016		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.4	$	0.4	$	—	$	—
Equity securities	3.4		—		3.4		—
Debt securities	4.4		—		4.4		—
Hedge funds	0.1		—		0.1		—
Real estate	0.3		—		0.3		—
Tangible assets	0.1		—		0.1		—
Total Master Trust assets	8.7		0.4		8.3		—
Derivative assets
FTRs	0.1		—		—		0.1
Interest rate hedges	1.2		—		1.2		—
Forward power contracts	19.5		—		19.5		—
Total Derivative assets	20.8		—		20.7		0.1
Total assets	$	29.5	$	0.4	$	29.0	$	0.1
Liabilities
Derivative liabilities
Interest rate hedges	$	0.7	$	—	$	0.7	$	—
Forward power contracts	28.5		—		26.0		2.5
Total Derivative liabilities	29.2		—		26.7		2.5
Long-term debt (a)	763.5		—		745.5		18.0
Total liabilities	$	792.7	$	—	$	772.2	$	20.5

(a) 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 that are in the Master Trust, which are valued using observable prices based on the end of day net asset value 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.

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 loan 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.

Approximately 89% of the inputs to the fair value of our derivative instruments are from quoted market prices.

Non-recurring Fair Value Measurements

We use the cost approach to determine the fair value of our AROs, which 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. As a result of changes in our estimates of costs to be incurred for our AROs, we decreased our AROs by $4.4 million in the first six months of 2017. AROs for ash ponds, asbestos, ash landfills, river structures and underground storage tanks decreased by a net amount of $1.6 million and increased by a net amount of $2.3 million during the six months ended June 30, 2017 and 2016, respectively. In addition, there was a $3.7 million decrease in the ARO liability during the six months ended June 30, 2017 related to AROs at Miami Fort and Zimmer being reclassified to Liabilities held for sale - current.

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 14 – Fixed-asset Impairments.

A ruling by the Supreme Court of Ohio on June 20, 2016, lower expectation of future capacity revenue resulting from the most recent PJM capacity auction and a higher anticipated level of environmental compliance costs resulting from third party studies were collectively determined to be an impairment indicator for these assets. As a result, we performed a long-lived asset impairment analysis during the second quarter of 2016 and determined that the carrying amount of Killen and certain DP&L peaking generating facilities were not recoverable. See Note 14 – 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:

$ in millions
	Carrying		Fair Value						Gross
	Amount (b)		Level 1		Level 2		Level 3		Loss
	Six months ended June 30, 2017
Assets
Long-lived assets (a)
Stuart	$	42.3	$	—	$	—	$	3.3	$	39.0
Killen	$	35.2	$	—	$	—	$	7.9	$	27.3
	Six months ended June 30, 2016
Assets
Long-lived assets (a)
Stuart	$	456.4	$	—	$	—	$	164.4	$	292.0
Killen	$	330.5	$	—	$	—	$	84.3	$	246.2
Zimmer	$	429.9	$	—	$	—	$	111.0	$	318.9

(a)See Note 14 – Fixed-asset Impairments for further information

(b)Carrying amount at date of valuation

The following summarizes the significant unobservable inputs used in the Level 3 measurement on a non-recurring basis during the six months ended June 30, 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	%
				Weighted-average cost of capital	7	%
Killen	$	7.9	Discounted cash flow	Pre-tax operating margin (through remaining life)	22	%
				Weighted-average cost of capital	7	%

The following summarizes the significant unobservable inputs used in the Level 3 measurement on a non-recurring basis during the six months ended June 30, 2016:

$ in millions	Fair value		Valuation technique	Unobservable input	Weighted average
Long-lived assets held and used:
Stuart	$	164.4	Discounted cash flow	Annual revenue growth	-9% to 10% (2%)
				Annual pre-tax operating margin	-29% to 52% (5%)
				Weighted-average cost of capital	9%
Killen	$	84.3	Discounted cash flow	Annual revenue growth	-11% to 13% (2%)
				Annual pre-tax operating margin	-50% to 67% (6%)
				Weighted-average cost of capital	11%
Zimmer	$	111.0	Discounted cash flow	Annual revenue growth	-14% to 13% (1%)
				Annual pre-tax operating margin	-46% to 80% (4%)
				Weighted-average cost of capital	9%

XML

Derivative Instruments and Hedging Activities

6 Months Ended

Jun. 30, 2017

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 arrangements, including derivative financial instruments. We use derivatives principally to manage the risk of changes in market prices for commodities. 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 normal purchase/normal sale, cash flow hedges or marked to market each reporting period.

At June 30, 2017, DPL had the following outstanding derivative instruments:

Commodity	Accounting Treatment (a)	Unit	Purchases (in thousands)		Sales (in thousands)			Net Purchases/ (Sales) (in thousands)
FTRs	Not designated	MWh	4.7		—			4.7
Natural gas futures	Not designated	Dths	18,490.0		(703.2		)	17,786.8
Forward power contracts	Designated	MWh	810.5		(4,014.2		)	(3,203.7		)
Forward power contracts	Not designated	MWh	1,426.0		(1,630.5		)	(204.5		)
Interest rate swaps	Designated	USD	$	200,000.0	$	—		$	200,000.0

(a)    Refers to whether the derivative instruments have been designated as a cash flow hedge.

At December 31, 2016, DPL had the following outstanding derivative instruments:

Commodity	Accounting Treatment (a)	Unit	Purchases (in thousands)		Sales (in thousands)			Net Purchases/ (Sales) (in thousands)
FTRs	Not designated	MWh	2.3		—			2.3
Natural gas futures	Not designated	Dths	1,590.0		—			1,590.0
Forward power contracts	Designated	MWh	342.9		(9,974.5		)	(9,631.6		)
Forward power contracts	Not designated	MWh	2,568.3		(2,020.9		)	547.4
Interest rate swaps	Designated	USD	$	200,000.0	$	—		$	200,000.0

(a)    Refers to whether the derivative instruments have been designated as a cash flow hedge.

Cash Flow Hedges

As part of our risk management processes, we identify the relationships between hedging instruments and hedged items, as well as the risk management objective and strategy for undertaking various hedge transactions. The fair value of cash flow hedges is determined by observable market prices available as of the balance sheet dates and 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.

We have two interest rate swaps to hedge the variable interest on our $200.0 million variable interest rate tax-exempt First Mortgage Bonds. The interest rate swaps have a combined notional amount of $200.0 million and will settle monthly based on a one month LIBOR. We use the income approach to value the swaps, which consists of forecasting future cash flows based on contractual notional amounts and applicable and available market data as of the valuation date. The most common market data inputs used in the income approach include volatilities, spot and forward benchmark interest rates (LIBOR). Forward rates with the same tenor as the derivative instrument being valued are generally obtained from published sources, with these forward rates being assessed quarterly at a portfolio-level for reasonableness versus comparable published rates. We reclassify gains and losses on the swaps out of AOCI and into earnings in those periods in which hedged interest payments occur.

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 table provides information for DPL concerning gains or losses recognized in AOCI for the cash flow hedges for the three and six months ended June 30, 2017 and 2016:

	Three months ended						Three months ended
	June 30, 2017						June 30, 2016
				Interest						Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge
Beginning accumulated derivative gains in AOCI	$	1.8		$	17.5		$	22.5		$	17.5
Net gains / (losses) associated with current period hedging transactions	1.2			(0.1		)	(8.5		)	—
Net gains / (losses) reclassified to earnings
Interest expense	—			(0.2		)	—			(0.2		)
Revenues	—			—			(13.0		)	—
Purchased power	—			—			2.4			—
Ending accumulated derivative gains in AOCI	$	3.0		$	17.2		$	3.4		$	17.3
	Six months ended						Six months ended
	June 30, 2017						June 30, 2016
				Interest						Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge
Beginning accumulated derivative gains / (losses) in AOCI	$	(4.3	)	$	17.4		$	9.2		$	17.5
Net gains associated with current period hedging transactions	6.0			0.1			13.0			—
Net gains / (losses) reclassified to earnings
Interest expense	—			(0.3		)	—			(0.2		)
Revenues	(0.8		)	—			(24.0		)	—
Purchased power	2.1			—			5.2			—
Ending accumulated derivative gains in AOCI	$	3.0		$	17.2		$	3.4		$	17.3
Portion expected to be reclassified to earnings in the next twelve months (a)	$	3.2		$	(0.6	)
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)	9			38

(a)The actual amounts that we reclassify from AOCI to earnings related to power can differ from the estimate above due to market price changes.

Derivatives not designated as hedges

Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for hedge accounting or the normal 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 and six months ended June 30, 2017 and 2016:

For the three months ended June 30, 2017
$ in millions	FTRs			Power			Natural Gas			Total
Change in unrealized gain / (loss)	$	(0.7	)	$	3.7		$	(0.6	)	$	2.4
Realized gain / (loss)	0.1			(0.7		)	—			(0.6		)
Total	$	(0.6	)	$	3.0		$	(0.6	)	$	1.8
Recorded in Income Statement: gain / (loss)
Revenues	$	—		$	(1.0	)	$	—		$	(1.0	)
Purchased power	(0.6		)	4.0			(0.6		)	2.8
Total	$	(0.6	)	$	3.0		$	(0.6	)	$	1.8

For the three months ended June 30, 2016
$ in millions	FTRs		Power			Natural Gas		Total
Change in unrealized gain / (loss)	$	0.2	$	2.6		$	0.5	$	3.3
Realized gain / (loss)	0.2		(2.4		)	0.7		(1.5		)
Total	$	0.4	$	0.2		$	1.2	$	1.8
Recorded in Income Statement: gain / (loss)
Revenues	$	—	$	(5.3	)	$	—	$	(5.3	)
Purchased power	0.4		5.5			1.2		7.1
Total	$	0.4	$	0.2		$	1.2	$	1.8

For the six months ended June 30, 2017
$ in millions	FTRs			Power			Natural Gas			Total
Change in unrealized gain / (loss)	$	(0.7	)	$	3.6		$	(0.7	)	$	2.2
Realized gain / (loss)	0.3			(3.3		)	(0.2		)	(3.2		)
Total	$	(0.4	)	$	0.3		$	(0.9	)	$	(1.0	)
Recorded in Income Statement: gain / (loss)
Revenues	$	—		$	(6.5	)	$	—		$	(6.5	)
Purchased power	(0.4		)	6.8			(0.9		)	5.5
Total	$	(0.4	)	$	0.3		$	(0.9	)	$	(1.0	)

For the six months ended June 30, 2016
$ in millions	FTRs		Power			Natural Gas		Total
Change in unrealized gain / (loss)	$	0.4	$	1.2		$	0.3	$	1.9
Realized gain / (loss)	0.4		(2.9		)	0.5		(2.0		)
Total	$	0.8	$	(1.7	)	$	0.8	$	(0.1	)
Recorded in Income Statement: gain / (loss)
Revenues	$	—	$	(6.6	)	$	—	$	(6.6	)
Purchased power	0.8		4.9			0.8		6.5
Total	$	0.8	$	(1.7	)	$	0.8	$	(0.1	)

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 June 30, 2017
				Gross Amounts Not Offset in the Condensed Consolidated Balance Sheets
$ in millions	Hedging Designation	Gross Fair Value as presented in the Condensed Consolidated Balance Sheets		Financial Instruments with Same Counterparty in Offsetting Position			Cash Collateral			Net Balance Fair Value
Assets
Short-term derivative positions (presented in Other prepayments and current assets)
Forward power contracts	Designated	$	10.2	$	(5.0	)	$	—		$	5.2
Forward power contracts	Not designated	5.1		(4.2		)	—			0.9
Natural gas futures	Not designated	0.1		—			—			0.1
Long-term derivative positions (presented in Other deferred assets)
Interest rate swap	Designated	0.9		—			—			0.9
Natural gas futures	Not designated	0.2		(0.2		)	—			—
Forward power contracts	Not designated	1.1		—			—			1.1
Total assets		$	17.6	$	(9.4	)	$	—		$	8.2
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Designated	$	5.3	$	(5.0	)	$	—		$	0.3
Interest rate swap	Designated	0.2		—			—			0.2
Forward power contracts	Not designated	4.5		(4.2		)	—			0.3
Natural gas futures	Not designated	0.7		—			(0.7		)	—
FTRs	Not designated	0.6		—			—			0.6
Long-term derivative positions (presented in Other deferred credits)
Natural gas futures	Not designated	0.3		(0.2		)	(0.1		)	—
Total liabilities		$	11.6	$	(9.4	)	$	(0.8	)	$	1.4

Fair Values of Derivative Instruments
at December 31, 2016
				Gross Amounts Not Offset in the Condensed Consolidated Balance Sheets
$ in millions	Hedging Designation	Gross Fair Value as presented in the Condensed Consolidated Balance Sheets		Financial Instruments with Same Counterparty in Offsetting Position			Cash Collateral			Net Balance Fair Value
Assets
Short-term derivative positions (presented in Other prepayments and current assets)
Forward power contracts	Designated	$	11.0	$	(10.5	)	$	—		$	0.5
Forward power contracts	Not designated	6.0		(4.7		)	—			1.3
FTRs	Not designated	0.1		—			—			0.1
Long-term derivative positions (presented in Other deferred assets)
Interest rate swaps	Designated	1.2		—			—			1.2
Forward power contracts	Designated	0.6		(0.6		)	—			—
Forward power contracts	Not designated	1.9		(1.0		)	—			0.9
Total assets		$	20.8	$	(16.8	)	$	—		$	4.0
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Interest rate swaps	Designated	$	0.7	$	—		$	—		$	0.7
Forward power contracts	Designated	16.4		(10.5		)	(5.5		)	0.4
Forward power contracts	Not designated	7.7		(4.7		)	—			3.0
Long-term derivative positions (presented in Other deferred credits)
Forward power contracts	Designated	2.4		(0.6		)	(0.8		)	1.0
Forward power contracts	Not designated	2.0		(1.0		)	—			1.0
Total liabilities		$	29.2	$	(16.8	)	$	(6.3	)	$	6.1

Credit risk-related contingent features

Certain of our OTC commodity derivative contracts are under master netting agreements that contain provisions that require us to post collateral if our credit ratings drop below certain thresholds. We have crossed this threshold and our counterparties could request that we post collateral for our net liability position with them. As of the date of the filing of this report, we have not had to post collateral with any of these counterparties.

The aggregate fair value of DPL’s commodity derivative instruments that were in a MTM loss position at June 30, 2017 was $11.6 million. $0.8 million of collateral was posted directly with third parties and in a broker margin account which offsets our loss positions on the forward contracts. This liability position is further offset by the asset position of counterparties with master netting agreements of $9.4 million. Since our long-term debt is below investment grade, we could have to post collateral for the remaining $1.4 million.

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 arrangements, including derivative financial instruments. We use derivatives principally to manage the risk of changes in market prices for commodities. 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 normal purchase/normal sale, cash flow hedges or marked to market each reporting period.

At June 30, 2017, DP&L had the following outstanding derivative instruments:

Commodity	Accounting Treatment (a)	Unit	Purchases (in thousands)		Sales (in thousands)			Net Purchases/ (Sales) (in thousands)
FTRs	Not designated	MWh	4.7		—			4.7
Natural gas futures	Not designated	Dths	18,490.0		(703.2		)	17,786.8
Forward power contracts	Designated	MWh	810.5		(4,014.2		)	(3,203.7		)
Forward power contracts	Not designated	MWh	1,426.0		(1,630.5		)	(204.5		)
Interest rate swaps	Designated	USD	$	200,000.0	$	—		$	200,000.0

(a)    Refers to whether the derivative instruments have been designated as a cash flow hedge.

At December 31, 2016, DP&L had the following outstanding derivative instruments:

Commodity	Accounting Treatment (a)	Unit	Purchases (in thousands)		Sales (in thousands)			Net Purchases/ (Sales) (in thousands)
FTRs	Not designated	MWh	2.3		—			2.3
Natural gas futures	Not designated	Dths	1,590.0		—			1,590.0
Forward power contracts	Designated	MWh	342.9		(9,974.5		)	(9,631.6		)
Forward power contracts	Not designated	MWh	2,568.3		(2,037.5		)	530.8
Interest rate swaps	Designated	USD	$	200,000.0	$	—		$	200,000.0

(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 value of cash flow hedges is determined by observable market prices available as of the balance sheet dates and 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.

We have two interest rate swaps to hedge the variable interest on our $200.0 million variable interest rate tax-exempt First Mortgage Bonds. The interest rate swaps have a combined notional amount of $200.0 million and will settle monthly based on a one month LIBOR. We use the income approach to value the swaps, which consists of forecasting future cash flows based on contractual notional amounts and applicable and available market data as of the valuation date. The most common market data inputs used in the income approach include volatilities, spot and forward benchmark interest rates (LIBOR). Forward rates with the same tenor as the derivative instrument being valued are generally obtained from published sources, with these forward rates being assessed quarterly at a portfolio-level for reasonableness versus comparable published rates. We reclassify gains and losses on the swaps out of AOCI and into earnings in those periods in which hedged interest payments occur.

The following table provides information for DP&L concerning gains or losses recognized in AOCI for the cash flow hedges for the three and six months ended June 30, 2017 and 2016:

	Three months ended						Three months ended
	June 30, 2017						June 30, 2016
				Interest						Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge
Beginning accumulated derivative gains in AOCI	$	1.8		$	1.7		$	22.5		$	1.8
Net gains / (losses) associated with current period hedging transactions	1.2			(0.1		)	(8.5		)	—
Net gains / (losses) reclassified to earnings
Interest expense	—			(0.2		)	—			(0.2		)
Revenues	—			—			(13.0		)	—
Purchased power	—			—			2.4			—
Ending accumulated derivative gains in AOCI	$	3.0		$	1.4		$	3.4		$	1.6
	Six months ended						Six months ended
	June 30, 2017						June 30, 2016
				Interest						Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge
Beginning accumulated derivative gains / (losses) in AOCI	$	(4.3	)	$	1.6		$	9.2		$	2.0
Net gains associated with current period hedging transactions	6.0			0.2			13.0			—
Net gains / (losses) reclassified to earnings
Interest expense	—			(0.4		)	—			(0.4		)
Revenues	(0.8		)	—			(24.0		)	—
Purchased power	2.1			—			5.2			—
Ending accumulated derivative gains in AOCI	$	3.0		$	1.4		$	3.4		$	1.6
Portion expected to be reclassified to earnings in the next twelve months (a)	$	3.2		$	(0.8	)
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)	9			38

(a) The actual amounts that we reclassify from AOCI to earnings related to power can differ from the estimate above due to market price changes.

Derivatives not designated as hedges

Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for hedge accounting or the normal 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 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 Statements of Operations on an accrual basis.

Financial Statement Effect

The following tables present the amount and classification within the Condensed Statements of Operations of the gains and losses on DP&L's derivatives not designated as hedging instruments for the three and six months ended June 30, 2017 and 2016:

For the three months ended June 30, 2017
$ in millions	FTRs			Power			Natural Gas			Total
Change in unrealized gain / (loss)	$	(0.7	)	$	3.7		$	(0.6	)	$	2.4
Realized gain / (loss)	0.1			(0.7		)	—			(0.6		)
Total	$	(0.6	)	$	3.0		$	(0.6	)	$	1.8
Recorded in Income Statement: gain / (loss)
Revenues	$	—		$	(1.1	)	$	—		$	(1.1	)
Purchased power	(0.6		)	4.1			(0.6		)	2.9
Total	$	(0.6	)	$	3.0		$	(0.6	)	$	1.8

For the three months ended June 30, 2016
$ in millions	FTRs		Power			Natural Gas		Total
Change in unrealized gain / (loss)	$	0.2	$	2.8		0.5		$	3.5
Realized gain / (loss)	0.2		(2.3		)	0.7		(1.4		)
Total	$	0.4	$	0.5		$	1.2	$	2.1
Recorded in Income Statement: gain / (loss)
Revenues	—		(5.1		)	—		(5.1		)
Purchased power	0.4		5.6			1.2		7.2
Total	$	0.4	$	0.5		$	1.2	$	2.1

For the six months ended June 30, 2017
$ in millions	FTRs			Power			Natural Gas			Total
Change in unrealized gain / (loss)	$	(0.7	)	$	3.6		$	(0.7	)	$	2.2
Realized gain / (loss)	0.3			(3.4		)	(0.2		)	(3.3		)
Total	$	(0.4	)	$	0.2		$	(0.9	)	$	(1.1	)
Recorded in Income Statement: gain / (loss)
Revenues	$	—		$	(6.6	)	$	—		$	(6.6	)
Purchased power	(0.4		)	6.8			(0.9		)	5.5
Total	$	(0.4	)	$	0.2		$	(0.9	)	$	(1.1	)

For the six months ended June 30, 2016
$ in millions	FTRs		Power			Natural Gas		Total
Change in unrealized gain / (loss)	$	0.4	$	0.9		0.3		$	1.6
Realized gain / (loss)	0.4		(2.7		)	0.5		(1.8		)
Total	$	0.8	$	(1.8	)	$	0.8	$	(0.2	)
Recorded in Income Statement: gain / (loss)
Revenues	—		(6.6		)	—		(6.6		)
Purchased power	0.8		4.8			0.8		6.4
Total	$	0.8	$	(1.8	)	$	0.8	$	(0.2	)

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 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 DP&L’s derivative instruments:

Fair Values of Derivative Instruments
at June 30, 2017
				Gross Amounts Not Offset in the Condensed Balance Sheets
$ in millions	Hedging Designation	Gross Fair Value as presented in the Condensed Balance Sheets		Financial Instruments with Same Counterparty in Offsetting Position			Cash Collateral			Net Balance Fair Value
Assets
Short-term derivative positions (presented in Other prepayments and current assets)
Forward power contracts	Designated	$	10.2	$	(5.0	)	$	—		$	5.2
Forward power contracts	Not designated	5.1		(4.2		)	—			0.9
Natural gas futures	Not designated	0.1		—			—			0.1
Long-term derivative positions (presented in Other deferred assets)
Interest rate swap	Designated	0.9		—			—			0.9
Natural gas futures	Not designated	0.2		(0.2		)	—			—
Forward power contracts	Not designated	1.1		—			—			1.1
Total assets		$	17.6	$	(9.4	)	$	—		$	8.2
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Designated	$	5.3	$	(5.0	)	$	—		$	0.3
Interest rate swaps	Designated	0.2		—			—			0.2
Forward power contracts	Not designated	4.5		(4.2		)	—			0.3
Natural gas futures	Not designated	0.7		—			(0.7		)	—
FTRs	Not designated	0.6		—			—			0.6
Long-term derivative positions (presented in Other deferred credits)
Natural gas futures	Not designated	0.3		(0.2		)	(0.1		)	—
Total liabilities		$	11.6	$	(9.4	)	$	(0.8	)	$	1.4

Fair Values of Derivative Instruments
at December 31, 2016
				Gross Amounts Not Offset in the Condensed Balance Sheets
$ in millions	Hedging Designation	Gross Fair Value as presented in the Condensed Balance Sheets		Financial Instruments with Same Counterparty in Offsetting Position			Cash Collateral			Net Balance Fair Value
Assets
Short-term derivative positions (presented in Other prepayments and current assets)
Forward power contracts	Designated	$	11.0	$	(10.5	)	$	—		$	0.5
Forward power contracts	Not designated	6.0		(4.7		)	—			1.3
FTRs	Not designated	0.1		—			—			0.1
Long-term derivative positions (presented in Other deferred assets)
Interest rate swaps	Designated	1.2		—			—			1.2
Forward power contracts	Designated	0.6		(0.6		)	—			—
Forward power contracts	Not designated	1.9		(1.0		)	—			0.9
Total assets		$	20.8	$	(16.8	)	$	—		$	4.0
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Designated	$	16.4	$	(10.5	)	$	(5.5	)	$	0.4
Interest rate swaps	Designated	0.7		—			—			0.7
Forward power contracts	Not designated	7.7		(4.7		)	—			3.0
Long-term derivative positions (presented in Other deferred credits)
Forward power contracts	Designated	2.4		(0.6		)	(0.8		)	1.0
Forward power contracts	Not designated	2.0		(1.0		)	—			1.0
Total liabilities		$	29.2	$	(16.8	)	$	(6.3	)	$	6.1

Credit risk-related contingent features

Certain of our OTC commodity derivative contracts are under master netting agreements that contain provisions that require us to post collateral if our credit ratings drop below certain thresholds. We have crossed this threshold and our counterparties could request that we post collateral for our net liability position with them. As of the date of the filing of this report, we have not had to post collateral with any of these counterparties.

The aggregate fair value of DP&L’s commodity derivative instruments that were in a MTM loss position at June 30, 2017 was $11.6 million. $0.8 million of collateral was posted directly with third parties and in a broker margin account which offsets our loss positions on the forward contracts. This liability position is further offset by the asset position of counterparties with master netting agreements of $9.4 million. Since our long-term debt is below investment grade, we could have to post collateral for the remaining $1.4 million.

XML

Debt Obligations

6 Months Ended

Jun. 30, 2017

Debt Instrument [Line Items]

Debt Obligations

Long-term Debt

The following table summarizes DPL's outstanding long-term debt.

	Interest		June 30,			December 31,
$ in millions	Rate	Maturity	2017			2016
Term loan - rates from 4.01% - 4.30% (a) and 4.00% - 4.01% (b)		2022	$	442.8		$	445.0
Tax-exempt First Mortgage Bonds	4.8%	2036	91.9			100.0
Tax-exempt First Mortgage Bonds - rates from 1.52% - 1.71% (a) and 1.29% - 1.42% (b)		2020	200.0			200.0
U.S. Government note	4.2%	2061	17.9			18.0
Capital leases			0.3			0.4
Unamortized deferred financing costs			(10.0		)	(10.7		)
Unamortized long-term debt discounts and premiums, net			(5.1		)	(5.5		)
Total long-term debt at consolidated subsidiary			737.8			747.2
Bank term loan - rates from 3.02% - 3.98% (a) and 2.67% - 3.02% (b)		2020	112.5			125.0
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
Unamortized deferred financing costs			(7.7		)	(8.8		)
Unamortized long-term debt discounts and premiums, net			(0.6		)	(0.6		)
Total long-term debt			1,837.6			1,858.4
Less: current portion			(50.9		)	(29.7		)
Long-term debt, net of current portion			$	1,786.7		$	1,828.7

(a) Range of interest rates for the six months endedJune 30, 2017.

(b) Range of interest rates for the year ended December 31, 2016.

(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.

Significant transactions

On May 26, 2017, DP&L commenced a tender offer to purchase any and all of the outstanding 4.8% tax-exempt First Mortgage Bonds at par value (plus accrued and unpaid interest). By June 23, 2017, or the expiration date of the tender, $8.1 million of the outstanding bonds were tendered. On June 26, 2017, DP&L accepted all of the tendered bonds, redeemed and retired them. On July 7, 2017, DP&L notified the Ohio Air Quality Development Authority and the Trustee of the same First Mortgage Bonds, which DP&L was going to call at par value (plus accrued and unpaid interest) $21.9 million of these bonds. As a result, this amount was included in the current portion of long-term debt as of June 30, 2017. On August 7, 2017, DP&L settled this call and subsequently redeemed and retired the bonds. At close of business on August 7,2017 and after considering both the $8.1 million tender and the $21.9 million call, DP&L’s tax-exempt First Mortgage Bonds had an outstanding principal balance of $70.0 million.

Long-term debt covenants and restrictions

DP&L’s unsecured revolving credit agreement and Bond Purchase and Covenants Agreement 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 ratio compares EBITDA to Interest Expense and 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.

On February 21, 2017, DP&L and its lenders amended DP&L’s revolving credit agreement and Bond Purchase and Covenant Agreement. These amendments modified the definition of Consolidated Net Worth (which is used for measuring the Total Debt to Total Capitalization ratio under each of the agreements), to exclude, through March 31, 2018, non-cash charges related directly to impairments of coal generation assets in DP&L's fiscal quarter ending December 31, 2016 and thereafter. With this amendment, DP&L’s Total Debt to Total Capitalization ratio for the period ending June 30, 2017 is 0.52 to 1.00. The amendment also changed, for each agreement, the dates after generation separation during which compliance with the Total Capitalization ratio detailed above shall be suspended if long-term indebtedness, as determined by the PUCO, is less than or equal to $750.0 million. This time period was originally January 1, 2017 to December 31, 2017, but is now the twelve months immediately subsequent to the separation of the generation assets from DP&L.

The cost of borrowing under DP&L's unsecured revolving credit agreement and Bond Purchase and Covenants Agreement adjust under certain credit rating scenarios.

DPL’s revolving credit agreement and term loan have two financial covenants. The first financial covenant, a Total Debt to EBITDA ratio, is calculated at the end of each fiscal quarter by dividing total debt at the end of the current quarter by consolidated EBITDA for the four prior fiscal quarters. The second financial covenant, an EBITDA to Interest Expense ratio, is calculated, at the end of each fiscal quarter, by dividing EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period.

The cost of borrowing under DPL's revolving credit agreement and term loan adjust under certain credit rating scenarios. DPL’s revolving credit agreement, term loan, and senior unsecured notes due 2019 restrict dividend payments from DPL to AES.

As of June 30, 2017, DP&L and DPL were in compliance with all debt covenants, including the financial covenants described above.

Substantially all property, plant & equipment of DP&L is subject to the lien of the mortgage securing DP&L’s First and Refunding Mortgage. In July 2017, assets related to the Miami Fort station and the Zimmer station were released from the lien of DP&L's First and Refunding Mortgage in connection with the pending sale. See Note 13 – Assets and Liabilities Held For Sale for additional information.

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		June 30,			December 31,
$ in millions	Rate	Maturity	2017			2016
Term loan - rates from 4.01% - 4.30% (a) and 4.00% - 4.01% (b)		2022	$	442.8		$	445.0
Tax-exempt First Mortgage Bonds	4.8%	2036	91.9			100.0
Tax-exempt First Mortgage Bonds - rates from 1.52% - 1.71% (a) and 1.29% - 1.42% (b)		2020	200.0			200.0
U.S. Government note	4.2%	2061	17.9			18.0
Capital leases			0.3			0.4
Unamortized deferred financing costs			(11.0		)	(11.8		)
Unamortized long-term debt discounts			(2.0		)	(2.2		)
Total long-term debt			739.9			749.4
Less: current portion			(26.4		)	(4.7		)
Long-term debt, net of current portion			$	713.5		$	744.7

(a)Range of interest rates for the six months ended June 30, 2017.

(b)Range of interest rates for the year ended December 31, 2016.

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.

Significant transactions

On May 26, 2017, DP&L commenced a tender offer to purchase any and all of the outstanding 4.8% tax-exempt First Mortgage Bonds at par value (plus accrued and unpaid interest). By June 23, 2017, or the expiration date of the tender, $8.1 million of the outstanding bonds were tendered. On June 26, 2017, DP&L accepted all of the tendered bonds, redeemed and retired them. On July 7, 2017, DP&L notified the Ohio Air Quality Development Authority and the Trustee of the same First Mortgage Bonds, which DP&L was going to call at par value (plus accrued and unpaid interest) $21.9 million of these bonds. As a result, this amount was included in the current portion of long-term debt as of June 30, 2017. On August 7, 2017, DP&L settled this call and subsequently redeemed and retired the bonds. At close of business on August 7,2017 and after considering both the $8.1 million tender and the $21.9 million call, DP&L’s tax-exempt First Mortgage Bonds had an outstanding principal balance of $70.0 million.

Debt covenants and restrictions

DP&L’s unsecured revolving credit agreement and Bond Purchase and Covenants Agreement 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 ratio compares EBITDA to Interest Expense and 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.

On February 21, 2017, DP&L and its lenders amended DP&L’s revolving credit agreement and Bond Purchase and Covenant Agreement. These amendments modified the definition of Consolidated Net Worth (which is used for measuring the Total Debt to Total Capitalization ratio under each of the agreements), to exclude, through March 31, 2018, non-cash charges related directly to impairments of coal generation assets in DP&L's fiscal quarter ending December 31, 2016 and thereafter. With this amendment, DP&L’s Total Debt to Total Capitalization ratio for the period ending June 30, 2017 is 0.52 to 1.00. The amendment also changed, for each agreement, the dates after generation separation during which compliance with the Total Capitalization ratio detailed above shall be suspended if long-term indebtedness, as determined by the PUCO, is less than or equal to $750.0 million. This time period was originally January 1, 2017 to December 31, 2017, but is now the twelve months immediately subsequent to the separation of the generation assets from DP&L.

As of June 30, 2017, DP&L was in compliance with all debt covenants, including the financial covenants described above.

The cost of borrowing under DP&L's unsecured revolving credit agreement and Bond Purchase and Covenants Agreement adjusts under certain credit rating scenarios.

Substantially all property, plant & equipment of DP&L is subject to the lien of the mortgage securing DP&L’s First and Refunding Mortgage. In July 2017, assets related to the Miami Fort station and the Zimmer station were released from the lien of DP&L's First and Refunding Mortgage in connection with the pending sale. See Note 13 – Assets and Liabilities Held For Sale for additional information.

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Income Taxes

6 Months Ended

Jun. 30, 2017

Entity Information [Line Items]

Income Taxes

Income Taxes

The following table details the effective tax rates for the three and six months ended June 30, 2017 and 2016.

	Three months ended		Six months ended
	June 30,		June 30,
	2017	2016	2017	2016
DPL	94.3%	39.2%	31.2%	39.5%

Income tax expense for the six months endedJune 30, 2017 and 2016 was calculated using the estimated annual effective income tax rates for 2017 and 2016 of 30.9% and 38.8%, 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 rates estimated could be materially different from the actual effective tax rates.

The decrease in the annual effective rate compared to the same period in 2016 is primarily due to the forecasted tax expense relating to flow-through depreciation and the projected manufacturer's production deduction.

For the three months ended June 30, 2017, DPL’s current period effective tax rate was greater than the estimated annual effective rate primarily due to the impact of the fixed-asset impairment recorded in the first quarter of 2017. See Note 14 – Fixed-asset Impairments for more information.

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 and six months ended June 30, 2017 and 2016.

	Three months ended		Six months ended
	June 30,		June 30,
	2017	2016	2017	2016
DP&L	38.8%	36.4%	31.3%	36.9%

Income tax expense for the three and six months ended June 30, 2017 and 2016 was calculated using the estimated annual effective income tax rates for 2017 and 2016 of 30.4% and 36.7%, 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 rates estimated could be materially different from the actual effective tax rates. To the extent that actual pre-tax results for the year differ from the forecasts applied to the most recent interim period, the rates estimated could be materially different from the actual effective tax rates.

The decrease in the annual effective rate compared to the same period in 2016 is primarily due to the forecasted tax expense relating to flow-through depreciation and the projected manufacturer's production deduction.

Income taxes paid, net, were $26.2 million and $0.1 million for the six months ended June 30, 2017 and 2016, respectively. For the six months ended June 30, 2017, the $26.2 million represented payments made to DPL.

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Benefit Plans

6 Months Ended

Jun. 30, 2017

Entity Information [Line Items]

Pension and Postretirement Benefits

Benefit Plans

DP&L sponsors a defined benefit pension plan for the vast 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 $5.0 million in employer contributions during each of the six months ended June 30, 2017 and 2016.

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 but are still participants in the DP&L plan.

The net periodic benefit cost of the pension benefit plans for the three and six months ended June 30, 2017 and 2016 was:

Net Periodic Benefit Cost	Pension
	Three months ended						Six months ended
	June 30,						June 30,
$ in millions	2017			2016			2017			2016
Service cost	$	1.4		$	1.4		$	2.8		$	2.8
Interest cost	3.5			3.7			7.1			7.4
Expected return on plan assets	(5.7		)	(5.7		)	(11.4		)	(11.4		)
Plan curtailment (a)	—			—			4.1			—
Amortization of unrecognized:
Prior service cost	0.2			0.5			0.6			1.0
Actuarial loss	1.4			1.1			2.7			2.1
Net periodic benefit cost	$	0.8		$	1.0		$	5.9		$	1.9

(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 14 – 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 $15.7 million at June 30, 2017 and $15.8 million at December 31, 2016 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 to be paid during	Pension
2017	$	12.5
2018	25.5
2019	26.0
2020	26.4
2021	26.7
2022 - 2026	139.6

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 vast 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 $5.0 million in employer contributions during each of the six months ended June 30, 2017 and 2016.

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 but are still participants in the DP&L plan.

The net periodic benefit cost of the pension benefit plans for the three and six months ended June 30, 2017 and 2016 was:

Net Periodic Benefit Cost	Pension
	Three months ended						Six months ended
	June 30,						June 30,
$ in millions	2017			2016			2017			2016
Service cost	$	1.4		$	1.4		$	2.8		$	2.8
Interest cost	3.5			3.7			7.1			7.4
Expected return on plan assets	(5.7		)	(5.7		)	(11.4		)	(11.4		)
Plan curtailment (a)	—			—			5.6			—
Amortization of unrecognized:
Prior service cost	0.3			0.7			0.8			1.5
Actuarial loss	2.3			1.8			4.5			3.6
Net periodic benefit cost	$	1.8		$	1.9		$	9.4		$	3.9

(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. See Note 14 – 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 $15.7 million at June 30, 2017 and $15.8 million at December 31, 2016 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 to be paid during	Pension
2017	$	12.5
2018	25.5
2019	26.0
2020	26.4
2021	26.7
2022 - 2026	139.6

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Shareholder's Equity

6 Months Ended

Jun. 30, 2017

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 June 30, 2017. All common shares are held by DP&L’s parent, DPL.

As part of the PUCO’s approval of the Merger, DP&L agreed to maintain a capital structure that includes an equity ratio, calculated as total equity divided by total capitalization, of at least 50 percent and to not have a negative retained earnings balance. After the fixed-asset impairments recorded in 2017 and 2016 and as of June 30, 2017, DP&L's equity ratio was 31% 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.

During the six months ended June 30,2017, DP&L paid $9.0 million in cash to DPL, which was treated as a return of capital reducing Other paid-in capital.

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Contractual Obligations, Commercial Commitments and Contingencies

6 Months Ended

Jun. 30, 2017

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 June 30, 2017, DPL had $33.1 million of guarantees on behalf of AES Ohio Generation to third parties for future financial or performance assurance under such agreements. The guarantee arrangements entered into by DPL with these third parties cover 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 $2.3 million at June 30, 2017 and December 31, 2016, 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. If OVEC defaulted on its debt payments, DP&L could be responsible for repayment of its share of OVEC's debt. As of June 30, 2017, this amount was 4.9%, or $71.8 million, of a $1,465.4 million debt obligation that has 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 June 30, 2017, 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, 2016.

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 in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims, tax examinations and other matters 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 June 30, 2017, 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. DP&L has installed emission control technology and is taking other measures to comply with required and anticipated reductions;

• Rules and future rules issued by the USEPA, 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.

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. If OVEC defaulted on its debt payments, DP&L could be responsible for repayment of its share of OVEC's debt. As of June 30, 2017, this amount was 4.9%, or $71.8 million, of a $1,465.4 million debt obligation that has 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 June 30, 2017, 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, 2016.

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 in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims, tax examinations and other matters 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 June 30, 2017, cannot be reasonably determined.

Environmental Matters

DP&L’s facilities and operations are subject to a wide range of federal, state and local environmental regulations and laws. The environmental issues that may affect us include:

• The federal CAA and state laws and regulations (including 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. DP&L has installed emission control technology and is taking other measures to comply with required and anticipated reductions;

• Rules and future rules issued by the USEPA, 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.

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Business Segments

6 Months Ended

Jun. 30, 2017

Segment Reporting Information [Line Items]

Business Segments

Business Segments

DPL currently manages the 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 520,000 retail customers who are located in a 6,000 square mile area of West Central Ohio. DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates, and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs. The T&D segment includes revenues and costs associated with our investment in OVEC and the historical results of DP&L’s Beckjord, Hutchings Coal, and East Bend generating facilities, which were either closed or sold in prior periods. As these assets will not be transferring to AES Ohio Generation when DP&L’s planned generation separation occurs, they are grouped with the T&D assets for segment reporting purposes. In addition, regulatory deferrals and collections, which include fuel deferrals in historical periods, are included in the T&D segment.

Generation Segment

The Generation segment is comprised of AES Ohio Generation and DP&L’s electric generation business. Beginning in 2001, Ohio law gave consumers the right to choose the electric generation supplier from whom they purchase retail generation services. AES Ohio Generation owns and operates peaking generating facilities, and DP&L owns multiple coal-fired and peaking electric generating facilities. Both AES Ohio Generation and DP&L primarily sell their generated energy and capacity into the PJM wholesale market as DP&L sources all of the generation for its SSO customers through a competitive bid process.

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		Other			Adjustments and Eliminations			DPL Consolidated
Three months ended June 30, 2017
Revenues from external customers	$	167.9	$	127.4	$	2.8		$	—		$	298.1
Intersegment revenues	0.3		—		1.3			(1.6		)	—
Total revenues	$	168.2	$	127.4	$	4.1		$	(1.6	)	$	298.1
Depreciation and amortization	$	18.6	$	4.9	$	3.0		$	—		$	26.5
Interest expense	$	7.8	$	0.2	$	19.4		$	—		$	27.4
Income / (loss) from continuing operations before income tax	$	15.1	$	13.2	$	(19.5	)	$	—		$	8.8
Cash capital expenditures	$	19.4	$	5.1	$	0.5		$	—		$	25.0

$ in millions	T&D		Generation			Other			Adjustments and Eliminations			DPL Consolidated
Three months ended June 30, 2016
Revenues from external customers	$	184.7	$	141.4		$	2.2		$	—		$	328.3
Intersegment revenues	0.4		—			0.9			(1.3		)	—
Total revenues	$	185.1	$	141.4		$	3.1		$	(1.3	)	$	328.3
Depreciation and amortization	$	17.6	$	20.8		$	(2.4	)	$	—		$	36.0
Fixed-asset Impairments (Note 14)	$	—	$	857.1		$	(621.6	)	$	—		$	235.5
Interest expense	$	5.6	$	0.1		$	20.3		$	—		$	26.0
Income / (loss) from continuing operations before income tax	$	29.8	$	(861.6	)	$	606.7		$	—		$	(225.1	)
Cash capital expenditures	$	18.1	$	23.3		$	—		$	—		$	41.4

$ in millions	T&D		Generation			Other			Adjustments and Eliminations			DPL Consolidated
Six months ended June 30, 2017
Revenues from external customers	$	357.7	$	259.2		$	5.1		$	—		$	622.0
Intersegment revenues	0.6		—			2.7			(3.3		)	—
Total revenues	$	358.3	$	259.2		$	7.8		$	(3.3	)	$	622.0
Depreciation and amortization	$	36.7	$	11.9		$	5.9		$	—		$	54.5
Fixed-asset Impairments (Note 14)	$	—	$	66.3		$	0.1		$	—		$	66.4
Interest expense	$	15.2	$	0.2		$	38.9		$	—		$	54.3
Income / (loss) from continuing operations before income tax	$	40.1	$	(73.6	)	$	(40.9	)	$	—		$	(74.4	)
Cash capital expenditures	$	45.7	$	19.2		$	1.5		$	—		$	66.4
At June 30, 2017
Total assets	$	1,647.5	$	354.9		$	622.5		$	(414.5	)	$	2,210.4

$ in millions	T&D		Generation			Other			Adjustments and Eliminations			DPL Consolidated
Six months ended June 30, 2016
Revenues from external customers	$	388.9	$	299.6		$	3.8		$	—		$	692.3
Intersegment revenues	0.7		—			2.2			(2.9		)	—
Total revenues	$	389.6	$	299.6		$	6.0		$	(2.9	)	$	692.3
Depreciation and amortization	$	34.8	$	39.4		$	(4.8	)	$	—		$	69.4
Fixed-asset Impairments (Note 14)	$	—	$	857.1		$	(621.6	)	$	—		$	235.5
Interest expense	$	11.0	$	0.2		$	41.2		$	(0.1	)	$	52.3
Income / (loss) from continuing operations before income tax	$	64.0	$	(873.9	)	$	587.6		$	—		$	(222.3	)
Cash capital expenditures	$	42.2	$	36.3		$	0.6		$	—		$	79.1
At December 31, 2016
Total assets	$	1,710.5	$	472.3		$	673.6		$	(437.2	)	$	2,419.2

Subsidiaries [Member]

Segment Reporting Information [Line Items]

Business Segments

Business Segments

DP&L currently manages the business through two reportable operating segments, the T&D segment and the Generation segment. The primary segment performance measure is income / (loss) from operations before income tax as management has concluded that income / (loss) from operations before income tax best reflects the underlying business performance of DP&L and is the most relevant measure considered in DP&L’s internal evaluation of the financial performance of its segments. The segments are discussed further below:

Transmission and Distribution Segment

The T&D segment is comprised primarily of DP&L’s electric transmission and distribution businesses, which distribute electricity to residential, commercial, industrial and governmental customers. DP&L distributes electricity to more than 520,000 retail customers who are located in a 6,000 square mile area of West Central Ohio. DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates, and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs. The T&D segment includes revenues and costs associated with our investment in OVEC and the historical results of DP&L’s Beckjord, Hutchings Coal, and East Bend generating facilities, which were either closed or sold in prior periods. As these assets will not be transferring to AES Ohio Generation when DP&L’s planned generation separation occurs, they are grouped with the T&D assets for segment reporting purposes. In addition, regulatory deferrals and collections, which include fuel deferrals in historical periods, are included in the T&D segment.

Generation Segment

The Generation segment is comprised of DP&L’s electric generation business. Beginning in 2001, Ohio law gave consumers the right to choose the electric generation supplier from whom they purchase retail generation services. DP&L's Generation segmentowns multiple coal-fired and peaking electric generating facilities. DP&L's Generation segment sells its generated energy and capacity into the wholesale market as DP&L sources all of the generation for its SSO customers through a competitive bid process.

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 cost of sales are eliminated in consolidation. Certain shared and corporate costs are allocated among reporting segments.

The following tables present financial information for each of DP&L’s reportable business segments:

$ in millions	T&D		Generation		Adjustments and Eliminations		DP&L Total
Three months ended June 30, 2017
Revenues from external customers	$	168.2	$	115.9	$	—	$	284.1
Intersegment revenues	—		—		—		—
Total revenues	$	168.2	$	115.9	$	—	$	284.1
Depreciation and amortization	$	18.6	$	3.4	$	—	$	22.0
Interest expense	$	7.8	$	—	$	—	$	7.8
Income from operations before income tax	$	15.1	$	11.2	$	—	$	26.3
Cash capital expenditures	$	19.4	$	4.1	$	—	$	23.5

$ in millions	T&D		Generation			Adjustments and Eliminations		DP&L Total
Three months ended June 30, 2016
Revenues from external customers	$	185.1	$	128.6		$	—	$	313.7
Intersegment revenues	—		—			—		—
Total revenues	$	185.1	$	128.6		$	—	$	313.7
Depreciation and amortization	$	17.6	$	19.2		$	—	$	36.8
Fixed-asset Impairments (Note 14)	$	—	$	857.1		$	—	$	857.1
Interest expense	$	5.3	$	0.1		$	—	$	5.4
Income / (loss) from operations before income tax	$	30.1	$	(865.4	)	$	—	$	(835.3	)
Cash capital expenditures	$	18.1	$	17.9		$	—	$	36.0

$ in millions	T&D		Generation			Adjustments and Eliminations		DP&L Total
Six months ended June 30, 2017
Revenues from external customers	$	358.3	$	236.9		$	—	$	595.2
Intersegment revenues	—		—			—		—
Total revenues	$	358.3	$	236.9		$	—	$	595.2
Depreciation and amortization	$	36.7	$	8.8		$	—	$	45.5
Fixed-asset Impairments (Note 14)	$	—	$	66.3		$	—	$	66.3
Interest expense	$	15.2	$	0.2		$	—	$	15.4
Income / (loss) from operations before income tax	$	40.1	$	(77.5	)	$	—	$	(37.4	)
Cash capital expenditures	$	45.7	$	11.9		$	—	$	57.6
At June 30, 2017
Total assets	$	1,647.5	$	201.1		$	—	$	1,848.6

$ in millions	T&D		Generation			Adjustments and Eliminations		DP&L Total
Six months ended June 30, 2016
Revenues from external customers	$	389.6	$	273.3		$	—	$	662.9
Intersegment revenues	—		—			—		—
Total revenues	$	389.6	$	273.3		$	—	$	662.9
Depreciation and amortization	$	34.8	$	36.3		$	—	$	71.1
Fixed-asset Impairments (Note 14)	$	—	$	857.1		$	—	$	857.1
Interest expense	$	10.5	$	0.2		$	—	$	10.7
Income / (loss) from operations before income tax	$	64.5	$	(853.7	)	$	—	$	(789.2	)
Cash capital expenditures	$	42.2	$	29.6		$	—	$	71.8
At December 31, 2016
Total assets	$	1,710.5	$	324.6		$	—	$	2,035.1

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Discontinued Operations

6 Months Ended

Jun. 30, 2017

Discontinued Operations and Disposal Groups [Abstract]

Discontinued Operations

Discontinued Operations

On January 1, 2016, DPL closed on the sale of DPLER, its competitive retail business. The sale agreement was signed on December 28, 2015 and DPL recorded a gain on this transaction of $49.2 million in the first quarter of 2016. The gain includes the impact of DPLER’s liability to DP&L that transferred with the sale on January 1, 2016 but was eliminated in consolidation as of December 31, 2015.

Operating activities related to DPLER have been reclassified to "Discontinued operations" in the Condensed Consolidated Statements of Operations for the six months endedJune 30,2016.

The following table summarizes the revenues, cost of revenues, operating expenses and income tax of discontinued operations for the periods indicated:

	Six months ended June 30,
$ in millions	2016
Operating expenses	$	(0.7	)
Loss from discontinued operations before income taxes	(0.7		)
Gain from disposal of discontinued operations	49.2
Income tax expense	18.9
Income on discontinued operations	$	29.6

Cash flows related to discontinued operations are included in our Condensed Consolidated Statements of Cash Flows. Cash flows from operating activities for discontinued operations were $(0.7) million for the six months endedJune 30,2016. Cash flows from investing activities for discontinued operations were $75.5 million for the six months endedJune 30,2016. All cash generated from discontinued operations was paid to DPL through dividends for all periods presented.

Assets and Liabilities Held For Sale

On April 21, 2017, DP&L and AES Ohio Generation entered into an Asset Purchase Agreement with subsidiaries of Dynegy Inc., for the sale of DP&L's undivided interests in the Zimmer Station and the Miami Fort Station for cash and the assumption of certain liabilities, including environmental liabilities. The cash purchase price is subject to adjustment at closing based on the amount of certain inventories, pre-paid amounts, employment benefits, insurance premiums, property taxes and other costs prior to closing. The sale is subject to approval by the FERC and is expected to close in the third quarter of 2017.

Accordingly, the assets and liabilities of Zimmer Station and Miami Fort Station were classified as held for sale as of June 30, 2017, but the plants did not meet the criteria to be reported as discontinued operations. The following table summarizes the major classes of assets and liabilities as of June 30, 2017:

$ in millions	June 30, 2017
Assets
Inventories	$	24.0
Property, plant & equipment, net	44.6
Total assets of the disposal group classified as held for sale in the balance sheet	$	68.6
Liabilities
Accounts payable	$	12.9
Accrued taxes	4.9
Asset retirement obligations	4.7
Other liabilities	0.7
Total liabilities of the disposal group classified as held for sale in the balance sheet	$	23.2

Zimmer Station and Miami Fort Station's results are reflected within continuing operations in the Condensed Consolidated Statements of Operations. The combined income / (loss) from continuing operations before income tax for Zimmer Station and Miami Fort Station was $3.0 million and $(9.7) million for the three months ended June 30, 2017 and 2016, respectively, and $2.2 million and $(16.2) million for the six months ended June 30, 2017 and 2016, respectively. Zimmer Station and Miami Fort Station are included in the Generation segment.

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Held for Sale (Notes)

6 Months Ended

Jun. 30, 2017

Long Lived Assets Held-for-sale [Line Items]

Discontinued Operations

Discontinued Operations

On January 1, 2016, DPL closed on the sale of DPLER, its competitive retail business. The sale agreement was signed on December 28, 2015 and DPL recorded a gain on this transaction of $49.2 million in the first quarter of 2016. The gain includes the impact of DPLER’s liability to DP&L that transferred with the sale on January 1, 2016 but was eliminated in consolidation as of December 31, 2015.

Operating activities related to DPLER have been reclassified to "Discontinued operations" in the Condensed Consolidated Statements of Operations for the six months endedJune 30,2016.

The following table summarizes the revenues, cost of revenues, operating expenses and income tax of discontinued operations for the periods indicated:

	Six months ended June 30,
$ in millions	2016
Operating expenses	$	(0.7	)
Loss from discontinued operations before income taxes	(0.7		)
Gain from disposal of discontinued operations	49.2
Income tax expense	18.9
Income on discontinued operations	$	29.6

Cash flows related to discontinued operations are included in our Condensed Consolidated Statements of Cash Flows. Cash flows from operating activities for discontinued operations were $(0.7) million for the six months endedJune 30,2016. Cash flows from investing activities for discontinued operations were $75.5 million for the six months endedJune 30,2016. All cash generated from discontinued operations was paid to DPL through dividends for all periods presented.

Assets and Liabilities Held For Sale

On April 21, 2017, DP&L and AES Ohio Generation entered into an Asset Purchase Agreement with subsidiaries of Dynegy Inc., for the sale of DP&L's undivided interests in the Zimmer Station and the Miami Fort Station for cash and the assumption of certain liabilities, including environmental liabilities. The cash purchase price is subject to adjustment at closing based on the amount of certain inventories, pre-paid amounts, employment benefits, insurance premiums, property taxes and other costs prior to closing. The sale is subject to approval by the FERC and is expected to close in the third quarter of 2017.

Accordingly, the assets and liabilities of Zimmer Station and Miami Fort Station were classified as held for sale as of June 30, 2017, but the plants did not meet the criteria to be reported as discontinued operations. The following table summarizes the major classes of assets and liabilities as of June 30, 2017:

$ in millions	June 30, 2017
Assets
Inventories	$	24.0
Property, plant & equipment, net	44.6
Total assets of the disposal group classified as held for sale in the balance sheet	$	68.6
Liabilities
Accounts payable	$	12.9
Accrued taxes	4.9
Asset retirement obligations	4.7
Other liabilities	0.7
Total liabilities of the disposal group classified as held for sale in the balance sheet	$	23.2

Zimmer Station and Miami Fort Station's results are reflected within continuing operations in the Condensed Consolidated Statements of Operations. The combined income / (loss) from continuing operations before income tax for Zimmer Station and Miami Fort Station was $3.0 million and $(9.7) million for the three months ended June 30, 2017 and 2016, respectively, and $2.2 million and $(16.2) million for the six months ended June 30, 2017 and 2016, respectively. Zimmer Station and Miami Fort Station are included in the Generation segment.

Subsidiaries [Member]

Long Lived Assets Held-for-sale [Line Items]

Discontinued Operations

Assets and Liabilities Held For Sale

On April 21, 2017, DP&L and AES Ohio Generation entered into an Asset Purchase Agreement with subsidiaries of Dynegy Inc., for the sale of DP&L's undivided interests in the Zimmer Station and the Miami Fort Station for cash and the assumption of certain liabilities, including environmental liabilities. The cash purchase price is subject to adjustment at closing based on the amount of certain inventories, pre-paid amounts, employment benefits, insurance premiums, property taxes and other costs prior to closing. The sale is subject to approval by the FERC and is expected to close in the third quarter of 2017.

Accordingly, the assets and liabilities of Zimmer Station and Miami Fort Station were classified as held for sale as of June 30, 2017, but the plants did not meet the criteria to be reported as discontinued operations. The following table summarizes the major classes of assets and liabilities as of June 30, 2017:

$ in millions	June 30, 2017
Assets
Inventories	$	24.0
Property, plant & equipment, net	44.6
Total assets of the disposal group classified as held for sale in the balance sheet	$	68.6
Liabilities
Accounts payable	$	12.9
Accrued taxes	4.9
Asset retirement obligations	3.7
Other liabilities	0.7
Total liabilities of the disposal group classified as held for sale in the balance sheet	$	22.2

Zimmer Station and Miami Fort Station's results are reflected within continuing operations in the Condensed Statements of Operations. The combined income / (loss) from continuing operations before income tax for Zimmer Station and Miami Fort Station was $3.0 million and $(9.7) million for the three months ended June 30, 2017 and 2016, respectively, and $2.2 million and $(16.2) million for the six months ended June 30, 2017 and 2016, respectively. Zimmer Station and Miami Fort Station are included in the Generation segment.

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Fixed-asset Impairment (Notes)

6 Months Ended

Jun. 30, 2017

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 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. We performed a long-lived asset impairment analysis and determined that the carrying amounts of the Facilities were not recoverable. The asset groups of Stuart Station and Killen Station were determined to have fair values of $3.3 million and $7.9 million, respectively, using the discounted cash flows under the income approach. As a result, we recognized asset impairment expense of $39.1 million and $27.3 million for Stuart Station and Killen Station, respectively.

Additionally, as a result of the decision to retire the Facilities by June 1, 2018, we concluded that inventory at these Facilities is considered obsolete. As a result, we recognized a loss on disposal of $9.8 million and $6.4 million for Stuart Station and Killen Station inventories, respectively, during the first quarter of 2017, which is recorded in Loss on asset disposal in the Condensed Consolidated Statements of Operations.

During the second quarter of 2016, we tested the recoverability of our long-lived assets at certain of our generation facilities at DP&L. A ruling by the Supreme Court of Ohio on June 20, 2016, lower expectation of future capacity revenue resulting from the most recent PJM capacity auction and a higher anticipated level of environmental compliance costs resulting from third party studies were collectively determined to be an impairment indicator for these assets. We performed a long-lived asset impairment analysis and determined that the carrying amount of Killen and certain DP&L peaking generating facilities were not recoverable. The asset groups of Killen and these DP&L peaking generating facilities were determined to have fair values of $84.3 million and $5.2 million, respectively, using the discounted cash flows under the income approach. As a result, we recognized asset impairment expense of $230.8 million and $4.7 million for Killen and these DP&L peaking generating facilities, respectively.

THE DAYTON POWER AND LIGHT COMPANY [Member]

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 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. 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 $39.0 million and $27.3 million for Stuart Station and Killen Station, respectively.

Additionally, as a result of the decision to retire the Facilities by June 1, 2018, we concluded that inventory at these Facilities is considered obsolete. As a result, we recognized a loss on disposal of $9.8 million and $6.4 million for Stuart Station and Killen Station inventories, respectively, during the first quarter of 2017, which is recorded in Loss on asset disposal in the Condensed Statements of Operations.

During the second quarter of 2016, we tested the recoverability of our long-lived assets at certain of our generation facilities at DP&L. A ruling by the Supreme Court of Ohio on June 20, 2016, lower expectation of future capacity revenue resulting from the most recent PJM capacity auction and a higher anticipated level of environmental compliance costs resulting from third party studies were collectively determined to be an impairment indicator for these assets. We performed a long-lived asset impairment analysis and determined that the carrying amount of the asset groups of Stuart, Killen and Zimmer were not recoverable. The asset groups of Stuart, Killen and Zimmer were determined to have fair values of $164.4 million, $84.3 million and $111.0 million, respectively, using the discounted cash flows under the income approach. As a result, we recognized asset impairment expense of $292.0 million, $246.2 million and $318.9 million for Stuart, Killen and Zimmer, respectively.

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Summary of Significant Accounting Policies (Policy)

6 Months Ended

Jun. 30, 2017

Significant Accounting Policies [Line Items]

Description of Business

Description of Business

DPL is a diversified regional energy company organized in 1985 under the laws of Ohio. DPL has two reportable segments: the Transmission and Distribution (T&D) segment and the Generation segment. See Note 11 – 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 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 520,000 customers located in West Central Ohio. Additionally, DP&L procures retail SSO electric service on behalf of residential, commercial, industrial and governmental customers in a6,000square mile area of West Central Ohio. DP&L owns undivided interests in multiple coal-fired and peaking electric generating facilities as well as numerous transmission facilities. DP&L sources 100% of the generation for its SSO customers through a competitive bid process. Principal industries located in DP&L’s service territory include automotive, food processing, paper, plastic, manufacturing and defense. DP&L's distribution sales reflect the general economic conditions, seasonal weather patterns, retail competition in our service territory and the market price of electricity. DP&L sells all of its energy and capacity into the wholesale market.

DPL’s other significant subsidiaries include AES Ohio Generation, which owns and operates peaking generating facilities from which it sells all of its energy and capacity into the wholesale market, and MVIC, our captive insurance company that provides insurance services to DPL and our subsidiaries. DPL owns all of the common stock of its subsidiaries.

DPL also has a wholly-owned business trust, DPL Capital Trust II, formed for the purpose of issuing trust capital securities to investors.

DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators while its generation business is deemed competitive under Ohio law. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates, and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs.

DPL and its subsidiaries employed 1,115 people as of June 30, 2017, of which 1,106 were employed by DP&L. Approximately 60% of all DPL employees are under a collective bargaining agreement that expires on October 31, 2017.

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. DP&L has undivided ownership interests in five coal-fired generating facilities, various peaking 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, 2016.

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 June 30, 2017; our results of operations for the three and six months ended June 30, 2017 and 2016 and our cash flows for the six months ended June 30, 2017 and 2016. 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 and six months ended June 30, 2017 may not be indicative of our results that will be realized for the full year ending December 31, 2017.

The preparation of financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the revenues and expenses of the periods reported. Actual results could differ from these estimates. Significant items subject to such estimates and judgments include: the carrying value of property, plant and equipment; unbilled revenues; the valuation of derivative instruments; the valuation of insurance and claims liabilities; the valuation of allowances for receivables and deferred income taxes; regulatory assets and liabilities; 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

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 June 30, 2017 and 2016 were $11.4 million and $11.6 million, respectively. The amounts of such taxes collected for the six months ended June 30, 2017 and 2016 were $23.9 million and $24.5 million, respectively.

Recently Issued Accounting Standards

New Accounting Pronouncements

The following table provides a brief description of recent accounting pronouncements that could have a material impact on our consolidated financial statements:

Accounting Standard	Description	Date of Adoption	Effect on the financial statements upon adoption
New Accounting Standards Adopted
2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting	The standard simplifies the following aspects of accounting for share-based payments awards: accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, statutory tax withholding requirements, classification of awards as either equity or liabilities and classification of employee taxes paid on statement of cash flows when an employer withholds shares for tax-withholding purposes. Transition method: The recognition of excess tax benefits and tax deficiencies arising from vesting or settlement were applied retrospectively. The elimination of the requirement that excess tax benefits be realized before they are recognized was adopted on a modified retrospective basis with a cumulative adjustment to the opening balance sheet.	January 1, 2017.	The primary effect of adoption was the recognition of excess tax benefits in our provision for income taxes in the period when the awards vest or are settled, rather than in paid-in-capital in the period when the excess tax benefits are realized. We will continue to estimate the number of awards that are expected to vest in our determination of the related periodic compensation cost. The adoption of this standard did not have a material impact on the consolidated financial statements.

Accounting Standard	Description	Date of Adoption	Effect on the financial statements upon adoption
New Accounting Standards Issued But Not Yet Effective
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.
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. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business	This standard provides guidance to assist the entities with evaluating when a set of transferred assets and activities is a business. Transition method: prospective.	January 1, 2018. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2016-18, Statement of Cash Flows (Topic 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. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory	This standard requires that an entity recognizes the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. Transition method: modified retrospective.	January 1, 2018. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
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, Leases (Topic 842)	The standard creates Topic 842, Leases which supersedes Topic 840, Leases, and introduces a lessee model that brings substantially all leases onto the balance sheet while retaining most of the principles of the existing lessor model in U.S. GAAP and aligning many of those principles with ASC 606, Revenue from Contracts with Customers. Transition method: modified retrospective approach with certain practical expedients.	January 1, 2019. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements. We intend to adopt the standard as of January 1, 2019.
2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-05 Revenue from Contracts with Customers (Topic 606)	See discussion of the ASUs below.	January 1, 2018.	We will adopt the standard on January 1, 2018; see below for the evaluation of the impact of its adoption on the consolidated financial statements.

THE DAYTON POWER AND LIGHT COMPANY [Member]

Significant Accounting Policies [Line Items]

Description of Business

Description of Business

DP&L is a public utility incorporated in 1911 under the laws of Ohio. Beginning in 2001, Ohio law gave Ohio consumers the right to choose the electric generation supplier from whom they purchase retail generation service; however, retail transmission and distribution services are still regulated. DP&L has the exclusive right to provide such transmission and distribution services to approximately 520,000 customers located in West Central Ohio. Additionally, DP&L procures retail SSO electric service on behalf of residential, commercial, industrial and governmental customers in a6,000square mile area of West Central Ohio. DP&L owns undivided interests in multiple coal-fired and peaking electric generating facilities as well as numerous transmission facilities. DP&L sources 100% of the generation for its SSO customers through a competitive bid process. Principal industries located in DP&L’s service territory include automotive, food processing, paper, plastic, manufacturing and defense. DP&L's distribution sales reflect the general economic conditions, seasonal weather patterns, retail competition in our service territory and the market price of electricity. DP&L sells all of its energy and capacity into the wholesale market.DP&L is a subsidiary of DPL.

DP&L has two reportable segments: the Transmission and Distribution (T&D) segment and the Generation segment. See Note 12 – Business Segments for more information relating to these reportable segments.

DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators while its generation business is deemed competitive under Ohio law. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates, and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs.

DP&L employed 1,106 people as of June 30, 2017. Approximately 61% of all employees are under a collective bargaining agreement which expires on October 31, 2017.

Financial Statement Presentation

Financial Statement Presentation

DP&L does not have any subsidiaries. DP&L has undivided ownership interests in five coal-fired generating facilities, various peaking 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 Statements of Operations.

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, 2016.

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 June 30, 2017; our results of operations for the three and six months ended June 30, 2017 and 2016 and our cash flows for the six months ended June 30, 2017 and 2016. 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 and six months ended June 30, 2017 may not be indicative of our results that will be realized for the full year ending December 31, 2017.

The preparation of financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the revenues and expenses of the periods reported. Actual results could differ from these estimates. Significant items subject to such estimates and judgments include: the carrying value of property, plant and equipment; unbilled revenues; the valuation of derivative instruments; the valuation of insurance and claims liabilities; the valuation of allowances for receivables and deferred income taxes; regulatory assets and liabilities; 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 June 30, 2017 and 2016 were $11.4 million and $11.6 million, respectively. The amounts of such taxes collected for the six months ended June 30, 2017 and 2016 were $23.9 million and $24.5 million, respectively.

Recently Issued Accounting Standards

New Accounting Pronouncements

The following table provides a brief description of recent accounting pronouncements that could have a material impact on our financial statements:

Accounting Standard	Description	Date of Adoption	Effect on the financial statements upon adoption
New Accounting Standards Adopted
2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting	The standard simplifies the following aspects of accounting for share-based payments awards: accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, statutory tax withholding requirements, classification of awards as either equity or liabilities and classification of employee taxes paid on statement of cash flows when an employer withholds shares for tax-withholding purposes. Transition method: The recognition of excess tax benefits and tax deficiencies arising from vesting or settlement were applied retrospectively. The elimination of the requirement that excess tax benefits be realized before they are recognized was adopted on a modified retrospective basis with a cumulative adjustment to the opening balance sheet.	January 1, 2017.	The primary effect of adoption was the recognition of excess tax benefits in our provision for income taxes in the period when the awards vest or are settled, rather than in paid-in-capital in the period when the excess tax benefits are realized. We will continue to estimate the number of awards that are expected to vest in our determination of the related periodic compensation cost. The adoption of this standard did not have a material impact on the financial statements.
New Accounting Standards Issued But Not Yet Effective
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.
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. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements.
2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business	This standard provides guidance to assist the entities with evaluating when a set of transferred assets and activities is a business. Transition method: prospective.	January 1, 2018. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements.

Accounting Standard	Description	Date of Adoption	Effect on the financial statements upon adoption
2016-18, 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. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements.
2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory	This standard requires that an entity recognizes the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. Transition method: modified retrospective.	January 1, 2018. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements.
2016-13, 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, Leases (Topic 842)	The standard creates Topic 842, Leases which supersedes Topic 840, Leases, and introduces a lessee model that brings substantially all leases onto the balance sheet while retaining most of the principles of the existing lessor model in U.S. GAAP and aligning many of those principles with ASC 606, Revenue from Contracts with Customers. Transition method: modified retrospective approach with certain practical expedients.	January 1, 2019. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements. We intend to adopt the standard as of January 1, 2019.
2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-05 Revenue from Contracts with Customers (Topic 606)	See discussion of the ASUs below.	January 1, 2018.	We will adopt the standard on January 1, 2018; see below for the evaluation of the impact of its adoption on the financial statements.

XML

Summary of Significant Accounting Policies (Tables)

6 Months Ended

Jun. 30, 2017

Related Party Transaction [Line Items]

Schedule of New Accounting Pronouncements

The following table provides a brief description of recent accounting pronouncements that could have a material impact on our consolidated financial statements:

Accounting Standard	Description	Date of Adoption	Effect on the financial statements upon adoption
New Accounting Standards Adopted
2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting	The standard simplifies the following aspects of accounting for share-based payments awards: accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, statutory tax withholding requirements, classification of awards as either equity or liabilities and classification of employee taxes paid on statement of cash flows when an employer withholds shares for tax-withholding purposes. Transition method: The recognition of excess tax benefits and tax deficiencies arising from vesting or settlement were applied retrospectively. The elimination of the requirement that excess tax benefits be realized before they are recognized was adopted on a modified retrospective basis with a cumulative adjustment to the opening balance sheet.	January 1, 2017.	The primary effect of adoption was the recognition of excess tax benefits in our provision for income taxes in the period when the awards vest or are settled, rather than in paid-in-capital in the period when the excess tax benefits are realized. We will continue to estimate the number of awards that are expected to vest in our determination of the related periodic compensation cost. The adoption of this standard did not have a material impact on the consolidated financial statements.

Accounting Standard	Description	Date of Adoption	Effect on the financial statements upon adoption
New Accounting Standards Issued But Not Yet Effective
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.
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. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business	This standard provides guidance to assist the entities with evaluating when a set of transferred assets and activities is a business. Transition method: prospective.	January 1, 2018. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2016-18, Statement of Cash Flows (Topic 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. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory	This standard requires that an entity recognizes the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. Transition method: modified retrospective.	January 1, 2018. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
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, Leases (Topic 842)	The standard creates Topic 842, Leases which supersedes Topic 840, Leases, and introduces a lessee model that brings substantially all leases onto the balance sheet while retaining most of the principles of the existing lessor model in U.S. GAAP and aligning many of those principles with ASC 606, Revenue from Contracts with Customers. Transition method: modified retrospective approach with certain practical expedients.	January 1, 2019. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements. We intend to adopt the standard as of January 1, 2019.
2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-05 Revenue from Contracts with Customers (Topic 606)	See discussion of the ASUs below.	January 1, 2018.	We will adopt the standard on January 1, 2018; see below for the evaluation of the impact of its adoption on the consolidated financial statements.

THE DAYTON POWER AND LIGHT COMPANY [Member]

Related Party Transaction [Line Items]

Schedule of New Accounting Pronouncements

The following table provides a brief description of recent accounting pronouncements that could have a material impact on our financial statements:

Accounting Standard	Description	Date of Adoption	Effect on the financial statements upon adoption
New Accounting Standards Adopted
2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting	The standard simplifies the following aspects of accounting for share-based payments awards: accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, statutory tax withholding requirements, classification of awards as either equity or liabilities and classification of employee taxes paid on statement of cash flows when an employer withholds shares for tax-withholding purposes. Transition method: The recognition of excess tax benefits and tax deficiencies arising from vesting or settlement were applied retrospectively. The elimination of the requirement that excess tax benefits be realized before they are recognized was adopted on a modified retrospective basis with a cumulative adjustment to the opening balance sheet.	January 1, 2017.	The primary effect of adoption was the recognition of excess tax benefits in our provision for income taxes in the period when the awards vest or are settled, rather than in paid-in-capital in the period when the excess tax benefits are realized. We will continue to estimate the number of awards that are expected to vest in our determination of the related periodic compensation cost. The adoption of this standard did not have a material impact on the financial statements.
New Accounting Standards Issued But Not Yet Effective
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.
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. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements.
2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business	This standard provides guidance to assist the entities with evaluating when a set of transferred assets and activities is a business. Transition method: prospective.	January 1, 2018. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements.

Accounting Standard	Description	Date of Adoption	Effect on the financial statements upon adoption
2016-18, 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. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements.
2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory	This standard requires that an entity recognizes the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. Transition method: modified retrospective.	January 1, 2018. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements.
2016-13, 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, Leases (Topic 842)	The standard creates Topic 842, Leases which supersedes Topic 840, Leases, and introduces a lessee model that brings substantially all leases onto the balance sheet while retaining most of the principles of the existing lessor model in U.S. GAAP and aligning many of those principles with ASC 606, Revenue from Contracts with Customers. Transition method: modified retrospective approach with certain practical expedients.	January 1, 2019. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our financial statements. We intend to adopt the standard as of January 1, 2019.
2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-05 Revenue from Contracts with Customers (Topic 606)	See discussion of the ASUs below.	January 1, 2018.	We will adopt the standard on January 1, 2018; see below for the evaluation of the impact of its adoption on the financial statements.

XML

Supplemental Financial Information (Tables)

6 Months Ended

Jun. 30, 2017

Supplemental Financial Information [Line Items]

Schedule of Supplemental Financial Information

Accounts receivable and Inventories are as follows at June 30, 2017 and December 31, 2016:

	June 30,			December 31,
$ in millions	2017			2016
Accounts receivable, net:
Unbilled revenue	$	15.5		$	43.0
Customer receivables	62.1			73.9
Amounts due from partners in jointly owned plants	3.6			12.7
Other	19.4			6.7
Provision for uncollectible accounts	(1.0		)	(1.2		)
Total accounts receivable, net	$	99.6		$	135.1
Inventories, at average cost:
Fuel and limestone	$	17.6		$	38.9
Plant materials and supplies	10.4			36.6
Other	1.3			1.7
Total inventories, at average cost	$	29.3		$	77.2

Reclassification out of Accumulated Other Comprehensive Income

The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the three and six months ended June 30, 2017 and 2016 are as follows:

Details about Accumulated Other Comprehensive Income / (Loss) components	Affected line item in the Condensed Consolidated Statements of Operations	Three months ended						Six months ended
		June 30,						June 30,
$ in millions		2017			2016			2017			2016
Gains and losses on Available-for-sale securities activity (Note 5):
	Other income	$	—		$	0.1		$	(0.1	)	$	—
Gains and losses on cash flow hedges (Note 6):
	Interest expense	(0.3		)	(0.3		)	(0.5		)	(0.5		)
	Revenue	0.1			(20.1		)	(1.3		)	(37.3		)
	Purchased power	—			3.7			3.3			8.1
	Total before income taxes	(0.2		)	(16.7		)	1.5			(29.7		)
	Tax expense / (benefit)	—			5.9			(0.5		)	10.7
	Net of income taxes	(0.2		)	(10.8		)	1.0			(19.0		)
Amortization of defined benefit pension items (Note 9):
	Operation and maintenance	0.1			0.1			1.4			0.2
	Tax benefit	—			—			(0.5		)	(0.2		)
	Net of income taxes	0.1			0.1			0.9			—
Total reclassifications for the period, net of income taxes		$	(0.1	)	$	(10.6	)	$	1.8		$	(19.0	)

Schedule of Accumulated Other Comprehensive Income (Loss)

The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the six months endedJune 30, 2017 are as follows:

$ in millions	Gains / (losses) on available-for-sale securities			Gains / (losses) on cash flow hedges		Change in unfunded pension obligation			Total
Balance January 1, 2017	$	0.6		$	13.1	$	(13.4	)	$	0.3
Other comprehensive income / (loss) before reclassifications	0.3			6.1		(1.5		)	4.9
Amounts reclassified from accumulated other comprehensive income / (loss)	(0.1		)	1.0		0.9			1.8
Net current period other comprehensive income / (loss)	0.2			7.1		(0.6		)	6.7
Balance June 30, 2017	$	0.8		$	20.2	$	(14.0	)	$	7.0

THE DAYTON POWER AND LIGHT COMPANY [Member]

Supplemental Financial Information [Line Items]

Schedule of Supplemental Financial Information

Accounts receivable and Inventories are as follows at June 30, 2017 and December 31, 2016:

	June 30,			December 31,
$ in millions	2017			2016
Accounts receivable, net:
Unbilled revenue	$	15.5		$	43.0
Customer receivables	55.9			71.2
Amounts due from partners in jointly owned plants	3.6			12.7
Amounts due from affiliates	2.1			2.9
Other	19.0			6.0
Provision for uncollectible accounts	(1.0		)	(1.2		)
Total accounts receivable, net	$	95.1		$	134.6
Inventories, at average cost:
Fuel and limestone	$	17.6		$	38.8
Plant materials and supplies	8.8			35.3
Other	1.3			1.7
Total inventories, at average cost	$	27.7		$	75.8

Reclassification out of Accumulated Other Comprehensive Income

The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the three and six months ended June 30, 2017 and 2016 are as follows:

Details about Accumulated Other Comprehensive Income / (Loss) components	Affected line item in the Condensed Statements of Operations	Three months ended						Six months ended
		June 30,						June 30,
$ in millions		2017			2016			2017			2016
Gains and losses on Available-for-sale securities activity (Note 5):
	Other income	$	—		$	0.1		$	(0.1	)	$	—
Gains and losses on cash flow hedges (Note 6):
	Interest expense	(0.3		)	(0.3		)	(0.6		)	(0.6		)
	Revenue	0.1			(20.1		)	(1.3		)	(37.2		)
	Purchased power	—			3.7			3.3			8.1
	Total before income taxes	(0.2		)	(16.7		)	1.4			(29.7		)
	Tax expense / (benefit)	—			5.9			(0.5		)	10.5
	Net of income taxes	(0.2		)	(10.8		)	0.9			(19.2		)
Amortization of defined benefit pension items (Note 9):
	Operation and maintenance	1.0			1.1			4.8			2.2
	Tax benefit	(0.3		)	(0.4		)	(1.6		)	(1.2		)
	Net of income taxes	0.7			0.7			3.2			1.0
Total reclassifications for the period, net of income taxes		$	0.5		$	(10.0	)	$	4.0		$	(18.2	)

Schedule of Accumulated Other Comprehensive Income (Loss)

The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the six months ended June 30, 2017 are as follows:

$ in millions	Gains / (losses) on available-for-sale securities			Gains / (losses) on cash flow hedges			Change in unfunded pension obligation			Total
Balance January 1, 2017	$	0.7		$	(2.7	)	$	(40.5	)	$	(42.5	)
Other comprehensive income / (loss) before reclassifications	0.3			6.2			(1.6		)	4.9
Amounts reclassified from accumulated other comprehensive income / (loss)	(0.1		)	0.9			3.2			4.0
Net current period other comprehensive income	0.2			7.1			1.6			8.9
Balance June 30, 2017	$	0.9		$	4.4		$	(38.9	)	$	(33.6	)

XML

Property, Plant and Equipment (Tables)

6 Months Ended

Jun. 30, 2017

Property, Plant and Equipment [Line Items]

Schedule of Jointly Owned Utility Plants [Table Text Block]

L

Schedule of Change in Asset Retirement Obligation [Table Text Block]

Changes in the Liability for Generation AROs

$ in millions
Balance January 1, 2017	$	138.8
Revisions to cash flow and timing estimates	(4.4		)
Accretion expense	2.0
Settlements	—
Reclassified to Liabilities held for sale	(4.7		)
Balance June 30, 2017	$	131.7

See Note 5 – Fair Value for further discussion on changes to our AROs.

Subsidiaries [Member]

Property, Plant and Equipment [Line Items]

Schedule of Jointly Owned Utility Plants [Table Text Block]

DP&L’s undivided ownership interest in such facilities at June 30, 2017, is as follows:

	DP&L Share		DP&L Carrying Value
	Ownership %	Summer Production Capacity (MW)	Gross Plant In Service ($ in millions)		Accumulated Depreciation ($ in millions)		Construction Work in Process ($ in millions)
Jointly-owned production units
Conesville - Unit 4	16.5	129	$	0.6	$	0.6	$	0.7
Killen - Unit 2	67.0	402	8.4		2.5		—
Miami Fort - Units 7 and 8 (a)	36.0	368	31.2		3.1		5.1
Stuart - Units 2 through 4	35.0	606	0.9		0.9		—
Zimmer - Unit 1 (a)	28.1	371	19.9		14.4		5.3
Transmission (at varying percentages)			99.3		67.1		—
Total		1,876	$	160.3	$	88.6	$	11.1

Schedule of Change in Asset Retirement Obligation [Table Text Block]

Changes in the Liability for Generation AROs

$ in millions
Balance January 1, 2017	$	135.2
Revisions to cash flow and timing estimates	(4.4		)
Accretion expense	2.8
Settlements	—
Reclassified to Liabilities held for sale	(3.7		)
Balance June 30, 2017	$	129.9

XML

Fair Value (Tables)

6 Months Ended

Jun. 30, 2017

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 June 30, 2017 and December 31, 2016. Information about the fair value of our derivative instruments can be found in Note 6 – Derivative Instruments and Hedging Activities.

	June 30, 2017				December 31, 2016
$ in millions	Cost		Fair Value		Cost		Fair Value
Assets
Money market funds	$	0.4	$	0.4	$	0.4	$	0.4
Equity securities	2.6		3.9		2.4		3.4
Debt securities	4.2		4.3		4.4		4.4
Hedge funds	0.1		0.1		—		0.1
Real estate	—		—		0.3		0.3
Tangible assets	0.1		0.1		0.1		0.1
Total Assets	$	7.4	$	8.8	$	7.6	$	8.7
	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities
Long-term debt (a)	$	1,837.3	$	1,926.2	$	1,858.0	$	1,907.7

Fair Value of Assets and Liabilities Measured on Recurring Basis

The fair value of assets and liabilities at June 30, 2017 and December 31, 2016 and the respective category within the fair value hierarchy for DPL was determined as follows:

Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
$ in millions	Fair value at June 30, 2017		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.4	$	0.4	$	—	$	—
Equity securities	3.9		—		3.9		—
Debt securities	4.3		—		4.3		—
Hedge funds	0.1		—		0.1		—
Tangible assets	0.1		—		0.1		—
Total Master Trust assets	8.8		0.4		8.4		—
Derivative Assets
Forward power contracts	16.4		—		16.4		—
Interest rate hedges	0.9		—		0.9		—
Natural gas	0.3		0.3		—		—
Total Derivative assets	17.6		0.3		17.3		—
Total Assets	$	26.4	$	0.7	$	25.7	$	—
Liabilities
Derivative Liabilities
Interest rate hedges	$	0.2	$	—	$	0.2	$	—
FTRs	0.6		—		—		0.6
Natural gas futures	1.0		1.0		—		—
Forward power contracts	9.8		—		9.8		—
Total Derivative liabilities	11.6		1.0		10.0		0.6
Long-term debt	1,926.3		—		1,908.4		17.9
Total Liabilities	$	1,937.9	$	1.0	$	1,918.4	$	18.5

Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
$ in millions	Fair value at December 31, 2016		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.4	$	0.4	$	—	$	—
Equity securities	3.4		—		3.4		—
Debt securities	4.4		—		4.4		—
Hedge funds	0.1		—		0.1		—
Real estate	0.3		—		0.3		—
Tangible assets	0.1		—		0.1		—
Total Master Trust assets	8.7		0.4		8.3		—
Derivative assets
Forward power contracts	19.5		—		19.5		—
Interest rate hedges	1.2		—		1.2		—
FTRs	0.1		—		—		0.1
Total Derivative assets	20.8		—		20.7		0.1
Total Assets	$	29.5	$	0.4	$	29.0	$	0.1
Liabilities
Derivative liabilities
Interest rate hedges	$	0.7	$	—	$	0.7	$	—
Forward power contracts	28.5		—		26.0		2.5
Total Derivative liabilities	29.2		—		26.7		2.5
Long-term debt	1,907.7		—		1,889.7		18.0
Total Liabilities	$	1,936.9	$	—	$	1,916.4	$	20.5

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:

$ in millions	Carrying		Fair Value						Gross
	Amount (b)		Level 1		Level 2		Level 3		Loss
	Six months ended June 30, 2017
Assets
Long-lived assets (a)
Stuart	$	42.4	$	—	$	—	$	3.3	$	39.1
Killen	$	35.2	$	—	$	—	$	7.9	$	27.3
	Six months ended June 30, 2016
Assets
Long-lived assets (a)
Killen	$	315.1	$	—	$	—	$	84.3	$	230.8
DP&L peaking facilities	$	9.9	$	—	$	—	$	5.2	$	4.7

(a)See Note 14 – Fixed-asset Impairments for further information

(b)Carrying amount at date of valuation

Fair Value Inputs, Assets, Quantitative Information [Table Text Block]

The following summarizes the significant unobservable inputs used in the Level 3 measurement on a non-recurring basis during the six months ended June 30, 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	%
				Weighted-average cost of capital	7	%
Killen	$	7.9	Discounted cash flow	Pre-tax operating margin (through remaining life)	22	%
				Weighted-average cost of capital	7	%

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 June 30, 2017 and December 31, 2016. Information about the fair value of our derivative instruments can be found in Note 6 – Derivative Instruments and Hedging Activities.

	June 30, 2017				December 31, 2016
$ in millions	Cost		Fair Value		Cost		Fair Value
Assets
Money market funds	$	0.4	$	0.4	$	0.4	$	0.4
Equity securities	2.6		3.9		2.4		3.4
Debt securities	4.2		4.3		4.4		4.4
Hedge funds	0.1		0.1		—		0.1
Real estate	—		—		0.3		0.3
Tangible assets	0.1		0.1		0.1		0.1
Total assets	$	7.4	$	8.8	$	7.6	$	8.7
	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities
Long-term debt (a)	$	739.6	$	753.0	$	749.0	$	763.5

Fair Value of Assets and Liabilities Measured on Recurring Basis

The fair value of assets and liabilities at June 30, 2017 and December 31, 2016 and the respective category within the fair value hierarchy for DP&L was determined as follows:

Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
$ in millions	Fair value at June 30, 2017		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.4	$	0.4	$	—	$	—
Equity securities	3.9		—		3.9		—
Debt securities	4.3		—		4.3		—
Hedge funds	0.1		—		0.1		—
Tangible assets	0.1		—		0.1		—
Total Master Trust assets	8.8		0.4		8.4		—
Derivative assets
Natural gas futures	0.3		0.3		—		—
Interest rate hedges	0.9		—		0.9		—
Forward power contracts	16.4		—		16.4		—
Total derivative assets	17.6		0.3		17.3		—
Total assets	$	26.4	$	0.7	$	25.7	$	—
Liabilities
Derivative liabilities
FTRs	$	0.6	$	—	$	—	$	0.6
Interest rate hedges	0.2		—		0.2		—
Natural gas futures	1.0		1.0		—		—
Forward power contracts	9.8		—		9.8		—
Total derivative liabilities	11.6		1.0		10.0		0.6
Long-term debt (a)	753.0		—		735.1		17.9
Total liabilities	$	764.6	$	1.0	$	745.1	$	18.5

(a) Amounts exclude immaterial capital lease obligations

Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
$ in millions	Fair value at December 31, 2016		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.4	$	0.4	$	—	$	—
Equity securities	3.4		—		3.4		—
Debt securities	4.4		—		4.4		—
Hedge funds	0.1		—		0.1		—
Real estate	0.3		—		0.3		—
Tangible assets	0.1		—		0.1		—
Total Master Trust assets	8.7		0.4		8.3		—
Derivative assets
FTRs	0.1		—		—		0.1
Interest rate hedges	1.2		—		1.2		—
Forward power contracts	19.5		—		19.5		—
Total Derivative assets	20.8		—		20.7		0.1
Total assets	$	29.5	$	0.4	$	29.0	$	0.1
Liabilities
Derivative liabilities
Interest rate hedges	$	0.7	$	—	$	0.7	$	—
Forward power contracts	28.5		—		26.0		2.5
Total Derivative liabilities	29.2		—		26.7		2.5
Long-term debt (a)	763.5		—		745.5		18.0
Total liabilities	$	792.7	$	—	$	772.2	$	20.5

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:

$ in millions
	Carrying		Fair Value						Gross
	Amount (b)		Level 1		Level 2		Level 3		Loss
	Six months ended June 30, 2017
Assets
Long-lived assets (a)
Stuart	$	42.3	$	—	$	—	$	3.3	$	39.0
Killen	$	35.2	$	—	$	—	$	7.9	$	27.3
	Six months ended June 30, 2016
Assets
Long-lived assets (a)
Stuart	$	456.4	$	—	$	—	$	164.4	$	292.0
Killen	$	330.5	$	—	$	—	$	84.3	$	246.2
Zimmer	$	429.9	$	—	$	—	$	111.0	$	318.9

(a)See Note 14 – Fixed-asset Impairments for further information

(b)Carrying amount at date of valuation

Fair Value Inputs, Assets, Quantitative Information [Table Text Block]

The following summarizes the significant unobservable inputs used in the Level 3 measurement on a non-recurring basis during the six months ended June 30, 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	%
				Weighted-average cost of capital	7	%
Killen	$	7.9	Discounted cash flow	Pre-tax operating margin (through remaining life)	22	%
				Weighted-average cost of capital	7	%

The following summarizes the significant unobservable inputs used in the Level 3 measurement on a non-recurring basis during the six months ended June 30, 2016:

$ in millions	Fair value		Valuation technique	Unobservable input	Weighted average
Long-lived assets held and used:
Stuart	$	164.4	Discounted cash flow	Annual revenue growth	-9% to 10% (2%)
				Annual pre-tax operating margin	-29% to 52% (5%)
				Weighted-average cost of capital	9%
Killen	$	84.3	Discounted cash flow	Annual revenue growth	-11% to 13% (2%)
				Annual pre-tax operating margin	-50% to 67% (6%)
				Weighted-average cost of capital	11%
Zimmer	$	111.0	Discounted cash flow	Annual revenue growth	-14% to 13% (1%)
				Annual pre-tax operating margin	-46% to 80% (4%)
				Weighted-average cost of capital	9%

XML

Derivative Instruments and Hedging Activities (Tables)

6 Months Ended

Jun. 30, 2017

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Schedule of Notional Amounts of Outstanding Derivative Positions

At June 30, 2017, DPL had the following outstanding derivative instruments:

Commodity	Accounting Treatment (a)	Unit	Purchases (in thousands)		Sales (in thousands)			Net Purchases/ (Sales) (in thousands)
FTRs	Not designated	MWh	4.7		—			4.7
Natural gas futures	Not designated	Dths	18,490.0		(703.2		)	17,786.8
Forward power contracts	Designated	MWh	810.5		(4,014.2		)	(3,203.7		)
Forward power contracts	Not designated	MWh	1,426.0		(1,630.5		)	(204.5		)
Interest rate swaps	Designated	USD	$	200,000.0	$	—		$	200,000.0

(a)    Refers to whether the derivative instruments have been designated as a cash flow hedge.

At December 31, 2016, DPL had the following outstanding derivative instruments:

Commodity	Accounting Treatment (a)	Unit	Purchases (in thousands)		Sales (in thousands)			Net Purchases/ (Sales) (in thousands)
FTRs	Not designated	MWh	2.3		—			2.3
Natural gas futures	Not designated	Dths	1,590.0		—			1,590.0
Forward power contracts	Designated	MWh	342.9		(9,974.5		)	(9,631.6		)
Forward power contracts	Not designated	MWh	2,568.3		(2,020.9		)	547.4
Interest rate swaps	Designated	USD	$	200,000.0	$	—		$	200,000.0

Gains or Losses Recognized in AOCI for the Cash Flow Hedges

The following table provides information for DPL concerning gains or losses recognized in AOCI for the cash flow hedges for the three and six months ended June 30, 2017 and 2016:

	Three months ended						Three months ended
	June 30, 2017						June 30, 2016
				Interest						Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge
Beginning accumulated derivative gains in AOCI	$	1.8		$	17.5		$	22.5		$	17.5
Net gains / (losses) associated with current period hedging transactions	1.2			(0.1		)	(8.5		)	—
Net gains / (losses) reclassified to earnings
Interest expense	—			(0.2		)	—			(0.2		)
Revenues	—			—			(13.0		)	—
Purchased power	—			—			2.4			—
Ending accumulated derivative gains in AOCI	$	3.0		$	17.2		$	3.4		$	17.3
	Six months ended						Six months ended
	June 30, 2017						June 30, 2016
				Interest						Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge
Beginning accumulated derivative gains / (losses) in AOCI	$	(4.3	)	$	17.4		$	9.2		$	17.5
Net gains associated with current period hedging transactions	6.0			0.1			13.0			—
Net gains / (losses) reclassified to earnings
Interest expense	—			(0.3		)	—			(0.2		)
Revenues	(0.8		)	—			(24.0		)	—
Purchased power	2.1			—			5.2			—
Ending accumulated derivative gains in AOCI	$	3.0		$	17.2		$	3.4		$	17.3
Portion expected to be reclassified to earnings in the next twelve months (a)	$	3.2		$	(0.6	)
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)	9			38

(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 and six months ended June 30, 2017 and 2016:

For the three months ended June 30, 2017
$ in millions	FTRs			Power			Natural Gas			Total
Change in unrealized gain / (loss)	$	(0.7	)	$	3.7		$	(0.6	)	$	2.4
Realized gain / (loss)	0.1			(0.7		)	—			(0.6		)
Total	$	(0.6	)	$	3.0		$	(0.6	)	$	1.8
Recorded in Income Statement: gain / (loss)
Revenues	$	—		$	(1.0	)	$	—		$	(1.0	)
Purchased power	(0.6		)	4.0			(0.6		)	2.8
Total	$	(0.6	)	$	3.0		$	(0.6	)	$	1.8

For the three months ended June 30, 2016
$ in millions	FTRs		Power			Natural Gas		Total
Change in unrealized gain / (loss)	$	0.2	$	2.6		$	0.5	$	3.3
Realized gain / (loss)	0.2		(2.4		)	0.7		(1.5		)
Total	$	0.4	$	0.2		$	1.2	$	1.8
Recorded in Income Statement: gain / (loss)
Revenues	$	—	$	(5.3	)	$	—	$	(5.3	)
Purchased power	0.4		5.5			1.2		7.1
Total	$	0.4	$	0.2		$	1.2	$	1.8

For the six months ended June 30, 2017
$ in millions	FTRs			Power			Natural Gas			Total
Change in unrealized gain / (loss)	$	(0.7	)	$	3.6		$	(0.7	)	$	2.2
Realized gain / (loss)	0.3			(3.3		)	(0.2		)	(3.2		)
Total	$	(0.4	)	$	0.3		$	(0.9	)	$	(1.0	)
Recorded in Income Statement: gain / (loss)
Revenues	$	—		$	(6.5	)	$	—		$	(6.5	)
Purchased power	(0.4		)	6.8			(0.9		)	5.5
Total	$	(0.4	)	$	0.3		$	(0.9	)	$	(1.0	)

For the six months ended June 30, 2016
$ in millions	FTRs		Power			Natural Gas		Total
Change in unrealized gain / (loss)	$	0.4	$	1.2		$	0.3	$	1.9
Realized gain / (loss)	0.4		(2.9		)	0.5		(2.0		)
Total	$	0.8	$	(1.7	)	$	0.8	$	(0.1	)
Recorded in Income Statement: gain / (loss)
Revenues	$	—	$	(6.6	)	$	—	$	(6.6	)
Purchased power	0.8		4.9			0.8		6.5
Total	$	0.8	$	(1.7	)	$	0.8	$	(0.1	)

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 June 30, 2017
				Gross Amounts Not Offset in the Condensed Consolidated Balance Sheets
$ in millions	Hedging Designation	Gross Fair Value as presented in the Condensed Consolidated Balance Sheets		Financial Instruments with Same Counterparty in Offsetting Position			Cash Collateral			Net Balance Fair Value
Assets
Short-term derivative positions (presented in Other prepayments and current assets)
Forward power contracts	Designated	$	10.2	$	(5.0	)	$	—		$	5.2
Forward power contracts	Not designated	5.1		(4.2		)	—			0.9
Natural gas futures	Not designated	0.1		—			—			0.1
Long-term derivative positions (presented in Other deferred assets)
Interest rate swap	Designated	0.9		—			—			0.9
Natural gas futures	Not designated	0.2		(0.2		)	—			—
Forward power contracts	Not designated	1.1		—			—			1.1
Total assets		$	17.6	$	(9.4	)	$	—		$	8.2
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Designated	$	5.3	$	(5.0	)	$	—		$	0.3
Interest rate swap	Designated	0.2		—			—			0.2
Forward power contracts	Not designated	4.5		(4.2		)	—			0.3
Natural gas futures	Not designated	0.7		—			(0.7		)	—
FTRs	Not designated	0.6		—			—			0.6
Long-term derivative positions (presented in Other deferred credits)
Natural gas futures	Not designated	0.3		(0.2		)	(0.1		)	—
Total liabilities		$	11.6	$	(9.4	)	$	(0.8	)	$	1.4

Fair Values of Derivative Instruments
at December 31, 2016
				Gross Amounts Not Offset in the Condensed Consolidated Balance Sheets
$ in millions	Hedging Designation	Gross Fair Value as presented in the Condensed Consolidated Balance Sheets		Financial Instruments with Same Counterparty in Offsetting Position			Cash Collateral			Net Balance Fair Value
Assets
Short-term derivative positions (presented in Other prepayments and current assets)
Forward power contracts	Designated	$	11.0	$	(10.5	)	$	—		$	0.5
Forward power contracts	Not designated	6.0		(4.7		)	—			1.3
FTRs	Not designated	0.1		—			—			0.1
Long-term derivative positions (presented in Other deferred assets)
Interest rate swaps	Designated	1.2		—			—			1.2
Forward power contracts	Designated	0.6		(0.6		)	—			—
Forward power contracts	Not designated	1.9		(1.0		)	—			0.9
Total assets		$	20.8	$	(16.8	)	$	—		$	4.0
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Interest rate swaps	Designated	$	0.7	$	—		$	—		$	0.7
Forward power contracts	Designated	16.4		(10.5		)	(5.5		)	0.4
Forward power contracts	Not designated	7.7		(4.7		)	—			3.0
Long-term derivative positions (presented in Other deferred credits)
Forward power contracts	Designated	2.4		(0.6		)	(0.8		)	1.0
Forward power contracts	Not designated	2.0		(1.0		)	—			1.0
Total liabilities		$	29.2	$	(16.8	)	$	(6.3	)	$	6.1

THE DAYTON POWER AND LIGHT COMPANY [Member]

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Schedule of Notional Amounts of Outstanding Derivative Positions

At June 30, 2017, DP&L had the following outstanding derivative instruments:

Commodity	Accounting Treatment (a)	Unit	Purchases (in thousands)		Sales (in thousands)			Net Purchases/ (Sales) (in thousands)
FTRs	Not designated	MWh	4.7		—			4.7
Natural gas futures	Not designated	Dths	18,490.0		(703.2		)	17,786.8
Forward power contracts	Designated	MWh	810.5		(4,014.2		)	(3,203.7		)
Forward power contracts	Not designated	MWh	1,426.0		(1,630.5		)	(204.5		)
Interest rate swaps	Designated	USD	$	200,000.0	$	—		$	200,000.0

(a)    Refers to whether the derivative instruments have been designated as a cash flow hedge.

At December 31, 2016, DP&L had the following outstanding derivative instruments:

Commodity	Accounting Treatment (a)	Unit	Purchases (in thousands)		Sales (in thousands)			Net Purchases/ (Sales) (in thousands)
FTRs	Not designated	MWh	2.3		—			2.3
Natural gas futures	Not designated	Dths	1,590.0		—			1,590.0
Forward power contracts	Designated	MWh	342.9		(9,974.5		)	(9,631.6		)
Forward power contracts	Not designated	MWh	2,568.3		(2,037.5		)	530.8
Interest rate swaps	Designated	USD	$	200,000.0	$	—		$	200,000.0

Gains or Losses Recognized in AOCI for the Cash Flow Hedges

The following table provides information for DP&L concerning gains or losses recognized in AOCI for the cash flow hedges for the three and six months ended June 30, 2017 and 2016:

	Three months ended						Three months ended
	June 30, 2017						June 30, 2016
				Interest						Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge
Beginning accumulated derivative gains in AOCI	$	1.8		$	1.7		$	22.5		$	1.8
Net gains / (losses) associated with current period hedging transactions	1.2			(0.1		)	(8.5		)	—
Net gains / (losses) reclassified to earnings
Interest expense	—			(0.2		)	—			(0.2		)
Revenues	—			—			(13.0		)	—
Purchased power	—			—			2.4			—
Ending accumulated derivative gains in AOCI	$	3.0		$	1.4		$	3.4		$	1.6
	Six months ended						Six months ended
	June 30, 2017						June 30, 2016
				Interest						Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge
Beginning accumulated derivative gains / (losses) in AOCI	$	(4.3	)	$	1.6		$	9.2		$	2.0
Net gains associated with current period hedging transactions	6.0			0.2			13.0			—
Net gains / (losses) reclassified to earnings
Interest expense	—			(0.4		)	—			(0.4		)
Revenues	(0.8		)	—			(24.0		)	—
Purchased power	2.1			—			5.2			—
Ending accumulated derivative gains in AOCI	$	3.0		$	1.4		$	3.4		$	1.6
Portion expected to be reclassified to earnings in the next twelve months (a)	$	3.2		$	(0.8	)
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)	9			38

(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 Statements of Operations of the gains and losses on DP&L's derivatives not designated as hedging instruments for the three and six months ended June 30, 2017 and 2016:

For the three months ended June 30, 2017
$ in millions	FTRs			Power			Natural Gas			Total
Change in unrealized gain / (loss)	$	(0.7	)	$	3.7		$	(0.6	)	$	2.4
Realized gain / (loss)	0.1			(0.7		)	—			(0.6		)
Total	$	(0.6	)	$	3.0		$	(0.6	)	$	1.8
Recorded in Income Statement: gain / (loss)
Revenues	$	—		$	(1.1	)	$	—		$	(1.1	)
Purchased power	(0.6		)	4.1			(0.6		)	2.9
Total	$	(0.6	)	$	3.0		$	(0.6	)	$	1.8

For the three months ended June 30, 2016
$ in millions	FTRs		Power			Natural Gas		Total
Change in unrealized gain / (loss)	$	0.2	$	2.8		0.5		$	3.5
Realized gain / (loss)	0.2		(2.3		)	0.7		(1.4		)
Total	$	0.4	$	0.5		$	1.2	$	2.1
Recorded in Income Statement: gain / (loss)
Revenues	—		(5.1		)	—		(5.1		)
Purchased power	0.4		5.6			1.2		7.2
Total	$	0.4	$	0.5		$	1.2	$	2.1

For the six months ended June 30, 2017
$ in millions	FTRs			Power			Natural Gas			Total
Change in unrealized gain / (loss)	$	(0.7	)	$	3.6		$	(0.7	)	$	2.2
Realized gain / (loss)	0.3			(3.4		)	(0.2		)	(3.3		)
Total	$	(0.4	)	$	0.2		$	(0.9	)	$	(1.1	)
Recorded in Income Statement: gain / (loss)
Revenues	$	—		$	(6.6	)	$	—		$	(6.6	)
Purchased power	(0.4		)	6.8			(0.9		)	5.5
Total	$	(0.4	)	$	0.2		$	(0.9	)	$	(1.1	)

For the six months ended June 30, 2016
$ in millions	FTRs		Power			Natural Gas		Total
Change in unrealized gain / (loss)	$	0.4	$	0.9		0.3		$	1.6
Realized gain / (loss)	0.4		(2.7		)	0.5		(1.8		)
Total	$	0.8	$	(1.8	)	$	0.8	$	(0.2	)
Recorded in Income Statement: gain / (loss)
Revenues	—		(6.6		)	—		(6.6		)
Purchased power	0.8		4.8			0.8		6.4
Total	$	0.8	$	(1.8	)	$	0.8	$	(0.2	)

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value

DP&L’s derivative instruments:

Fair Values of Derivative Instruments
at June 30, 2017
				Gross Amounts Not Offset in the Condensed Balance Sheets
$ in millions	Hedging Designation	Gross Fair Value as presented in the Condensed Balance Sheets		Financial Instruments with Same Counterparty in Offsetting Position			Cash Collateral			Net Balance Fair Value
Assets
Short-term derivative positions (presented in Other prepayments and current assets)
Forward power contracts	Designated	$	10.2	$	(5.0	)	$	—		$	5.2
Forward power contracts	Not designated	5.1		(4.2		)	—			0.9
Natural gas futures	Not designated	0.1		—			—			0.1
Long-term derivative positions (presented in Other deferred assets)
Interest rate swap	Designated	0.9		—			—			0.9
Natural gas futures	Not designated	0.2		(0.2		)	—			—
Forward power contracts	Not designated	1.1		—			—			1.1
Total assets		$	17.6	$	(9.4	)	$	—		$	8.2
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Designated	$	5.3	$	(5.0	)	$	—		$	0.3
Interest rate swaps	Designated	0.2		—			—			0.2
Forward power contracts	Not designated	4.5		(4.2		)	—			0.3
Natural gas futures	Not designated	0.7		—			(0.7		)	—
FTRs	Not designated	0.6		—			—			0.6
Long-term derivative positions (presented in Other deferred credits)
Natural gas futures	Not designated	0.3		(0.2		)	(0.1		)	—
Total liabilities		$	11.6	$	(9.4	)	$	(0.8	)	$	1.4

Fair Values of Derivative Instruments
at December 31, 2016
				Gross Amounts Not Offset in the Condensed Balance Sheets
$ in millions	Hedging Designation	Gross Fair Value as presented in the Condensed Balance Sheets		Financial Instruments with Same Counterparty in Offsetting Position			Cash Collateral			Net Balance Fair Value
Assets
Short-term derivative positions (presented in Other prepayments and current assets)
Forward power contracts	Designated	$	11.0	$	(10.5	)	$	—		$	0.5
Forward power contracts	Not designated	6.0		(4.7		)	—			1.3
FTRs	Not designated	0.1		—			—			0.1
Long-term derivative positions (presented in Other deferred assets)
Interest rate swaps	Designated	1.2		—			—			1.2
Forward power contracts	Designated	0.6		(0.6		)	—			—
Forward power contracts	Not designated	1.9		(1.0		)	—			0.9
Total assets		$	20.8	$	(16.8	)	$	—		$	4.0
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Designated	$	16.4	$	(10.5	)	$	(5.5	)	$	0.4
Interest rate swaps	Designated	0.7		—			—			0.7
Forward power contracts	Not designated	7.7		(4.7		)	—			3.0
Long-term derivative positions (presented in Other deferred credits)
Forward power contracts	Designated	2.4		(0.6		)	(0.8		)	1.0
Forward power contracts	Not designated	2.0		(1.0		)	—			1.0
Total liabilities		$	29.2	$	(16.8	)	$	(6.3	)	$	6.1

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Debt (Tables)

6 Months Ended

Jun. 30, 2017

Debt Instrument [Line Items]

Long-term Debt

	Interest		June 30,			December 31,
$ in millions	Rate	Maturity	2017			2016
Term loan - rates from 4.01% - 4.30% (a) and 4.00% - 4.01% (b)		2022	$	442.8		$	445.0
Tax-exempt First Mortgage Bonds	4.8%	2036	91.9			100.0
Tax-exempt First Mortgage Bonds - rates from 1.52% - 1.71% (a) and 1.29% - 1.42% (b)		2020	200.0			200.0
U.S. Government note	4.2%	2061	17.9			18.0
Capital leases			0.3			0.4
Unamortized deferred financing costs			(10.0		)	(10.7		)
Unamortized long-term debt discounts and premiums, net			(5.1		)	(5.5		)
Total long-term debt at consolidated subsidiary			737.8			747.2
Bank term loan - rates from 3.02% - 3.98% (a) and 2.67% - 3.02% (b)		2020	112.5			125.0
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
Unamortized deferred financing costs			(7.7		)	(8.8		)
Unamortized long-term debt discounts and premiums, net			(0.6		)	(0.6		)
Total long-term debt			1,837.6			1,858.4
Less: current portion			(50.9		)	(29.7		)
Long-term debt, net of current portion			$	1,786.7		$	1,828.7

THE DAYTON POWER AND LIGHT COMPANY [Member]

Debt Instrument [Line Items]

Long-term Debt

	Interest		June 30,			December 31,
$ in millions	Rate	Maturity	2017			2016
Term loan - rates from 4.01% - 4.30% (a) and 4.00% - 4.01% (b)		2022	$	442.8		$	445.0
Tax-exempt First Mortgage Bonds	4.8%	2036	91.9			100.0
Tax-exempt First Mortgage Bonds - rates from 1.52% - 1.71% (a) and 1.29% - 1.42% (b)		2020	200.0			200.0
U.S. Government note	4.2%	2061	17.9			18.0
Capital leases			0.3			0.4
Unamortized deferred financing costs			(11.0		)	(11.8		)
Unamortized long-term debt discounts			(2.0		)	(2.2		)
Total long-term debt			739.9			749.4
Less: current portion			(26.4		)	(4.7		)
Long-term debt, net of current portion			$	713.5		$	744.7

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Income Taxes (Tables)

6 Months Ended

Jun. 30, 2017

Entity Information [Line Items]

Schedule of Effective Income Tax Rates

The following table details the effective tax rates for the three and six months ended June 30, 2017 and 2016.

	Three months ended		Six months ended
	June 30,		June 30,
	2017	2016	2017	2016
DPL	94.3%	39.2%	31.2%	39.5%

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 and six months ended June 30, 2017 and 2016.

	Three months ended		Six months ended
	June 30,		June 30,
	2017	2016	2017	2016
DP&L	38.8%	36.4%	31.3%	36.9%

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Benefit Plans (Tables)

6 Months Ended

Jun. 30, 2017

Entity Information [Line Items]

Schedule of Net Periodic Benefit Cost / (Income)

The net periodic benefit cost of the pension benefit plans for the three and six months ended June 30, 2017 and 2016 was:

Net Periodic Benefit Cost	Pension
	Three months ended						Six months ended
	June 30,						June 30,
$ in millions	2017			2016			2017			2016
Service cost	$	1.4		$	1.4		$	2.8		$	2.8
Interest cost	3.5			3.7			7.1			7.4
Expected return on plan assets	(5.7		)	(5.7		)	(11.4		)	(11.4		)
Plan curtailment (a)	—			—			4.1			—
Amortization of unrecognized:
Prior service cost	0.2			0.5			0.6			1.0
Actuarial loss	1.4			1.1			2.7			2.1
Net periodic benefit cost	$	0.8		$	1.0		$	5.9		$	1.9

(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 14 – 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 to be paid during	Pension
2017	$	12.5
2018	25.5
2019	26.0
2020	26.4
2021	26.7
2022 - 2026	139.6

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 and six months ended June 30, 2017 and 2016 was:

Net Periodic Benefit Cost	Pension
	Three months ended						Six months ended
	June 30,						June 30,
$ in millions	2017			2016			2017			2016
Service cost	$	1.4		$	1.4		$	2.8		$	2.8
Interest cost	3.5			3.7			7.1			7.4
Expected return on plan assets	(5.7		)	(5.7		)	(11.4		)	(11.4		)
Plan curtailment (a)	—			—			5.6			—
Amortization of unrecognized:
Prior service cost	0.3			0.7			0.8			1.5
Actuarial loss	2.3			1.8			4.5			3.6
Net periodic benefit cost	$	1.8		$	1.9		$	9.4		$	3.9

(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. See Note 14 – 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 to be paid during	Pension
2017	$	12.5
2018	25.5
2019	26.0
2020	26.4
2021	26.7
2022 - 2026	139.6

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Business Segments (Tables)

6 Months Ended

Jun. 30, 2017

Segment Reporting Information [Line Items]

Financial Reporting for Reportable Business Segments

$ in millions	T&D		Generation			Other			Adjustments and Eliminations			DPL Consolidated
Six months ended June 30, 2017
Revenues from external customers	$	357.7	$	259.2		$	5.1		$	—		$	622.0
Intersegment revenues	0.6		—			2.7			(3.3		)	—
Total revenues	$	358.3	$	259.2		$	7.8		$	(3.3	)	$	622.0
Depreciation and amortization	$	36.7	$	11.9		$	5.9		$	—		$	54.5
Fixed-asset Impairments (Note 14)	$	—	$	66.3		$	0.1		$	—		$	66.4
Interest expense	$	15.2	$	0.2		$	38.9		$	—		$	54.3
Income / (loss) from continuing operations before income tax	$	40.1	$	(73.6	)	$	(40.9	)	$	—		$	(74.4	)
Cash capital expenditures	$	45.7	$	19.2		$	1.5		$	—		$	66.4
At June 30, 2017
Total assets	$	1,647.5	$	354.9		$	622.5		$	(414.5	)	$	2,210.4

$ in millions	T&D		Generation			Other			Adjustments and Eliminations			DPL Consolidated
Six months ended June 30, 2016
Revenues from external customers	$	388.9	$	299.6		$	3.8		$	—		$	692.3
Intersegment revenues	0.7		—			2.2			(2.9		)	—
Total revenues	$	389.6	$	299.6		$	6.0		$	(2.9	)	$	692.3
Depreciation and amortization	$	34.8	$	39.4		$	(4.8	)	$	—		$	69.4
Fixed-asset Impairments (Note 14)	$	—	$	857.1		$	(621.6	)	$	—		$	235.5
Interest expense	$	11.0	$	0.2		$	41.2		$	(0.1	)	$	52.3
Income / (loss) from continuing operations before income tax	$	64.0	$	(873.9	)	$	587.6		$	—		$	(222.3	)
Cash capital expenditures	$	42.2	$	36.3		$	0.6		$	—		$	79.1
At December 31, 2016
Total assets	$	1,710.5	$	472.3		$	673.6		$	(437.2	)	$	2,419.2

Subsidiaries [Member]

Segment Reporting Information [Line Items]

Financial Reporting for Reportable Business Segments

The following tables present financial information for each of DP&L’s reportable business segments:

$ in millions	T&D		Generation		Adjustments and Eliminations		DP&L Total
Three months ended June 30, 2017
Revenues from external customers	$	168.2	$	115.9	$	—	$	284.1
Intersegment revenues	—		—		—		—
Total revenues	$	168.2	$	115.9	$	—	$	284.1
Depreciation and amortization	$	18.6	$	3.4	$	—	$	22.0
Interest expense	$	7.8	$	—	$	—	$	7.8
Income from operations before income tax	$	15.1	$	11.2	$	—	$	26.3
Cash capital expenditures	$	19.4	$	4.1	$	—	$	23.5

$ in millions	T&D		Generation			Adjustments and Eliminations		DP&L Total
Three months ended June 30, 2016
Revenues from external customers	$	185.1	$	128.6		$	—	$	313.7
Intersegment revenues	—		—			—		—
Total revenues	$	185.1	$	128.6		$	—	$	313.7
Depreciation and amortization	$	17.6	$	19.2		$	—	$	36.8
Fixed-asset Impairments (Note 14)	$	—	$	857.1		$	—	$	857.1
Interest expense	$	5.3	$	0.1		$	—	$	5.4
Income / (loss) from operations before income tax	$	30.1	$	(865.4	)	$	—	$	(835.3	)
Cash capital expenditures	$	18.1	$	17.9		$	—	$	36.0

$ in millions	T&D		Generation			Adjustments and Eliminations		DP&L Total
Six months ended June 30, 2017
Revenues from external customers	$	358.3	$	236.9		$	—	$	595.2
Intersegment revenues	—		—			—		—
Total revenues	$	358.3	$	236.9		$	—	$	595.2
Depreciation and amortization	$	36.7	$	8.8		$	—	$	45.5
Fixed-asset Impairments (Note 14)	$	—	$	66.3		$	—	$	66.3
Interest expense	$	15.2	$	0.2		$	—	$	15.4
Income / (loss) from operations before income tax	$	40.1	$	(77.5	)	$	—	$	(37.4	)
Cash capital expenditures	$	45.7	$	11.9		$	—	$	57.6
At June 30, 2017
Total assets	$	1,647.5	$	201.1		$	—	$	1,848.6

$ in millions	T&D		Generation			Adjustments and Eliminations		DP&L Total
Six months ended June 30, 2016
Revenues from external customers	$	389.6	$	273.3		$	—	$	662.9
Intersegment revenues	—		—			—		—
Total revenues	$	389.6	$	273.3		$	—	$	662.9
Depreciation and amortization	$	34.8	$	36.3		$	—	$	71.1
Fixed-asset Impairments (Note 14)	$	—	$	857.1		$	—	$	857.1
Interest expense	$	10.5	$	0.2		$	—	$	10.7
Income / (loss) from operations before income tax	$	64.5	$	(853.7	)	$	—	$	(789.2	)
Cash capital expenditures	$	42.2	$	29.6		$	—	$	71.8
At December 31, 2016
Total assets	$	1,710.5	$	324.6		$	—	$	2,035.1

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Discontinued Operations (Tables)

6 Months Ended

Jun. 30, 2017

Discontinued Operations and Disposal Groups [Abstract]

Disposal Groups, Including Discontinued Operations [Table Text Block]

The following table summarizes the revenues, cost of revenues, operating expenses and income tax of discontinued operations for the periods indicated:

	Six months ended June 30,
$ in millions	2016
Operating expenses	$	(0.7	)
Loss from discontinued operations before income taxes	(0.7		)
Gain from disposal of discontinued operations	49.2
Income tax expense	18.9
Income on discontinued operations	$	29.6

Accordingly, the assets and liabilities of Zimmer Station and Miami Fort Station were classified as held for sale as of June 30, 2017, but the plants did not meet the criteria to be reported as discontinued operations. The following table summarizes the major classes of assets and liabilities as of June 30, 2017:

$ in millions	June 30, 2017
Assets
Inventories	$	24.0
Property, plant & equipment, net	44.6
Total assets of the disposal group classified as held for sale in the balance sheet	$	68.6
Liabilities
Accounts payable	$	12.9
Accrued taxes	4.9
Asset retirement obligations	4.7
Other liabilities	0.7
Total liabilities of the disposal group classified as held for sale in the balance sheet	$	23.2

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Held for Sale (Tables)

6 Months Ended

Jun. 30, 2017

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 expenses and income tax of discontinued operations for the periods indicated:

	Six months ended June 30,
$ in millions	2016
Operating expenses	$	(0.7	)
Loss from discontinued operations before income taxes	(0.7		)
Gain from disposal of discontinued operations	49.2
Income tax expense	18.9
Income on discontinued operations	$	29.6

Accordingly, the assets and liabilities of Zimmer Station and Miami Fort Station were classified as held for sale as of June 30, 2017, but the plants did not meet the criteria to be reported as discontinued operations. The following table summarizes the major classes of assets and liabilities as of June 30, 2017:

$ in millions	June 30, 2017
Assets
Inventories	$	24.0
Property, plant & equipment, net	44.6
Total assets of the disposal group classified as held for sale in the balance sheet	$	68.6
Liabilities
Accounts payable	$	12.9
Accrued taxes	4.9
Asset retirement obligations	4.7
Other liabilities	0.7
Total liabilities of the disposal group classified as held for sale in the balance sheet	$	23.2

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]

Accordingly, the assets and liabilities of Zimmer Station and Miami Fort Station were classified as held for sale as of June 30, 2017, but the plants did not meet the criteria to be reported as discontinued operations. The following table summarizes the major classes of assets and liabilities as of June 30, 2017:

$ in millions	June 30, 2017
Assets
Inventories	$	24.0
Property, plant & equipment, net	44.6
Total assets of the disposal group classified as held for sale in the balance sheet	$	68.6
Liabilities
Accounts payable	$	12.9
Accrued taxes	4.9
Asset retirement obligations	3.7
Other liabilities	0.7
Total liabilities of the disposal group classified as held for sale in the balance sheet	$	22.2

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Summary of Significant Accounting Policies (Narrative) (Details) $ in Millions	1 Months Ended	3 Months Ended		6 Months Ended
	Jan. 31, 2016	Jun. 30, 2017 USD ($) employee	Jun. 30, 2016 USD ($)	Jun. 30, 2017 USD ($) mi² employee segment generating_facility customer	Jun. 30, 2016 USD ($)
Significant Accounting Policies [Line Items]
Number of reportable segments | segment				2
Entity number of employees | employee		1,115		1,115
Employees under a collective bargaining agreement which expires in October-2011				60.00%
Excise taxes collected | $		$ 11.4	$ 11.6	$ 23.9	$ 24.5
THE DAYTON POWER AND LIGHT COMPANY [Member]
Significant Accounting Policies [Line Items]
Approximate number of retail customers | customer				520,000
Service area, square miles | mi²				6,000
Number of Operating Segments | segment				2
Entity number of employees | employee		1,106		1,106
Employees under a collective bargaining agreement which expires in October-2011				61.00%
Number Of Generating Facilities | generating_facility				5
Excise taxes collected | $		$ 11.4	$ 11.6	$ 23.9	$ 24.5
Year 2016 [Member]
Significant Accounting Policies [Line Items]
Electric generation through competitive bid	100.00%

XML

Supplemental Financial Information (Supplemental Financial Information) (Details) - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Supplemental Financial Information [Line Items]
Unbilled revenue	$ 15.5	$ 43.0
Customer receivables	62.1	73.9
Amounts due from partners in jointly owned stations	3.6	12.7
Other	19.4	6.7
Provision for uncollectible accounts	(1.0)	(1.2)
Total accounts receivable, net	99.6	135.1
Fuel and limestone	17.6	38.9
Plant materials and supplies	10.4	36.6
Other	1.3	1.7
Total inventories, at average cost	29.3	77.2
THE DAYTON POWER AND LIGHT COMPANY [Member]
Supplemental Financial Information [Line Items]
Unbilled revenue	15.5	43.0
Customer receivables	55.9	71.2
Amounts due from partners in jointly owned stations	3.6	12.7
Amounts due from affiliates	2.1	2.9
Other	19.0	6.0
Provision for uncollectible accounts	(1.0)	(1.2)
Total accounts receivable, net	95.1	134.6
Fuel and limestone	17.6	38.8
Plant materials and supplies	8.8	35.3
Other	1.3	1.7
Total inventories, at average cost	$ 27.7	$ 75.8

XML

Supplemental Financial Information (Reclassification out of ACOI) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Other income	$ (28.2)	$ (26.0)	$ (56.1)	$ (55.4)
Tax expense	(8.3)	88.3	23.2	87.7
Net income / (loss)	0.5	(136.8)	(51.2)	(105.0)
Interest expense	(27.4)	(26.0)	(54.3)	(52.3)
Revenue	298.1	328.3	622.0	692.3
Purchased power	(77.4)	(96.9)	(179.4)	(218.8)
Operating Expenses	(129.7)	(370.3)	(352.8)	(513.3)
THE DAYTON POWER AND LIGHT COMPANY [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Other income	(8.2)	(5.2)	(16.7)	(10.8)
Tax expense	(10.2)	303.7	11.7	291.3
Net income / (loss)	16.1	(531.6)	(25.7)	(497.9)
Interest expense	(7.8)	(5.4)	(15.4)	(10.7)
Revenue	284.1	313.7	595.2	662.9
Purchased power	(76.4)	(96.7)	(177.2)	(218.0)
Operating Expenses	(123.3)	(991.5)	(338.7)	(1,104.8)
Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Net income / (loss)	(0.1)	(10.6)	1.8	(19.0)
Reclassification out of Accumulated Other Comprehensive Income [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Net income / (loss)	0.5	(10.0)	4.0	(18.2)
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	(0.1)	0.0
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	(0.1)	0.0
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	0.0	5.9	(0.5)	10.7
Net income / (loss)	(0.2)	(10.8)	1.0	(19.0)
Interest expense	(0.3)	(0.3)	(0.5)	(0.5)
Revenue	0.1	(20.1)	(1.3)	(37.3)
Purchased power	0.0	3.7	3.3	8.1
Total before income taxes	(0.2)	(16.7)	1.5	(29.7)
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	0.0	5.9	(0.5)	10.5
Net income / (loss)	(0.2)	(10.8)	0.9	(19.2)
Interest expense	(0.3)	(0.3)	(0.6)	(0.6)
Revenue	0.1	(20.1)	(1.3)	(37.2)
Purchased power	0.0	3.7	3.3	8.1
Total before income taxes	(0.2)	(16.7)	1.4	(29.7)
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	0.0	0.0	(0.5)	(0.2)
Net income / (loss)	0.1	0.1	0.9	0.0
Operating Expenses	0.1	0.1	1.4	0.2
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	(0.3)	(0.4)	(1.6)	(1.2)
Net income / (loss)	0.7	0.7	3.2	1.0
Operating Expenses	$ 1.0	$ 1.1	$ 4.8	$ 2.2

XML

Supplemental Financial Information (Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period			$ 0.3
Other comprehensive loss before reclassifications			4.9
Amounts reclassified from accumulated other comprehensive income / (loss)			1.8
Other comprehensive loss	$ 1.1	$ (19.2)	6.7	$ (5.9)
Balance, end of period	7.0		7.0
THE DAYTON POWER AND LIGHT COMPANY [Member]
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period			(42.5)
Other comprehensive loss before reclassifications			4.9
Amounts reclassified from accumulated other comprehensive income / (loss)			4.0
Other comprehensive loss	1.7	$ (18.6)	8.9	$ (5.1)
Balance, end of period	(33.6)		(33.6)
Gains / (losses) on available-for-sale securities [Member]
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period			0.6
Other comprehensive loss before reclassifications			0.3
Amounts reclassified from accumulated other comprehensive income / (loss)			(0.1)
Other comprehensive loss			0.2
Balance, end of period	0.8		0.8
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			0.7
Other comprehensive loss before reclassifications			0.3
Amounts reclassified from accumulated other comprehensive income / (loss)			(0.1)
Other comprehensive loss			0.2
Balance, end of period	0.9		0.9
Gains / (losses) on cash flow hedges [Member]
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period			13.1
Other comprehensive loss before reclassifications			6.1
Amounts reclassified from accumulated other comprehensive income / (loss)			1.0
Other comprehensive loss			7.1
Balance, end of period	20.2		20.2
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			(2.7)
Other comprehensive loss before reclassifications			6.2
Amounts reclassified from accumulated other comprehensive income / (loss)			0.9
Other comprehensive loss			7.1
Balance, end of period	4.4		4.4
Change in unfunded pension obligation [Member]
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period			(13.4)
Other comprehensive loss before reclassifications			(1.5)
Amounts reclassified from accumulated other comprehensive income / (loss)			0.9
Other comprehensive loss			(0.6)
Balance, end of period	(14.0)		(14.0)
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			(40.5)
Other comprehensive loss before reclassifications			(1.6)
Amounts reclassified from accumulated other comprehensive income / (loss)			3.2
Other comprehensive loss			1.6
Balance, end of period	$ (38.9)		$ (38.9)

XML

Regulatory Matters (Details) - USD ($)			12 Months Ended
	Mar. 13, 2017	Oct. 11, 2016	Dec. 31, 2016
Distribution Modernization Rider		$ 145,000,000
Distribution Modernization Rider Period		7 years
Regulatory Assets, Renewable Energy Recovery		$ 10,500,000
Energy Reduction Riders		0
Non-bypassable DMR	$ 105,000,000
Service stability rider per year			$ 110,000,000
Subsidiaries [Member]
Distribution Modernization Rider		$ 145,000,000
Distribution Modernization Rider Period		7 years
Regulatory Assets, Renewable Energy Recovery		$ 10,500,000
Energy Reduction Riders		$ 0
Non-bypassable DMR	$ 105,000,000
Service stability rider per year			$ 110,000,000

XML

Property, Plant and Equipment (Details) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017 USD ($)	Jun. 30, 2016 USD ($)	Jun. 30, 2017 USD ($) generating_facility power_plant MW	Jun. 30, 2016 USD ($)	Apr. 21, 2017 USD ($)	Dec. 31, 2016 USD ($)
Property, Plant and Equipment [Line Items]
Asset Retirement Obligation	$ 131.7		$ 131.7			$ 138.8
Asset Retirement Obligation, Revision of Estimate			(4.4)
Asset Retirement Obligation, Accretion Expense			2.0
Asset Retirement Obligation, Liabilities Settled			0.0
Gain (Loss) on Sale of Assets and Asset Impairment Charges	3.2	$ 0.0	(16.2)	$ (0.1)
Electric Transmission [Member] | Dpandl Investment [Member]
Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	43.9		43.9
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	11.7		11.7
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	11.1		11.1
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	104.9		104.9
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	33.2		$ 33.2
Total Jointly Owned Stations [Member] | Dpandl Share [Member]
Property, Plant and Equipment [Line Items]
Production Plan Capacity | MW			1,876
Conesville Unit Four [Member] | Dpandl Investment [Member]
Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	0.7		$ 0.7
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	0.6		0.6
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	$ 0.6		$ 0.6
Conesville Unit Four [Member] | Dpandl Share [Member]
Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	16.50%		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		$ 0.0
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	8.4		8.4
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	$ 2.5		$ 2.5
Killen Station [Member] | Dpandl Share [Member]
Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	67.00%		67.00%
Miami Fort Unit Seven And Eight [Member] | Dpandl Investment [Member]
Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	$ 5.1		$ 5.1
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	31.2		31.2
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	$ 3.1		$ 3.1
Miami Fort Unit Seven And Eight [Member] | Dpandl Share [Member]
Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	36.00%		36.00%
Stuart Station [Member] | Dpandl Investment [Member]
Property, Plant and Equipment [Line Items]
Write off of net book value			$ 6.4
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	$ 0.0		0.0
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	0.9		0.9
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	$ 0.9		0.9
Gain (Loss) on Sale of Assets and Asset Impairment Charges			$ 3.2
Stuart Station [Member] | Dpandl Share [Member]
Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	35.00%		35.00%
Zimmer Station [Member] | Dpandl Investment [Member]
Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	$ 5.3		$ 5.3
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	19.9		19.9
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	$ 14.4		$ 14.4
Zimmer Station [Member] | Dpandl Share [Member]
Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	28.10%		28.10%
Miami Fort and Zimmer [Member]
Property, Plant and Equipment [Line Items]
Asset Retirement Obligation, Held for Sale	$ (4.7)		$ (4.7)
Miami Fort and Zimmer [Member] | Dpandl Investment [Member]
Property, Plant and Equipment [Line Items]
Sale of undivided interest in jointly-owned production units					$ 50.0
Subsidiaries [Member]
Property, Plant and Equipment [Line Items]
Number Of Coal Fired Power Plants | power_plant			5
Asset Retirement Obligation	129.9		$ 129.9			$ 135.2
Asset Retirement Obligation, Revision of Estimate			$ (4.4)
Number Of Generating Facilities | generating_facility			5
Asset Retirement Obligation, Accretion Expense			$ 2.8
Asset Retirement Obligation, Liabilities Settled			0.0
Gain (Loss) on Sale of Assets and Asset Impairment Charges	3.2	$ (0.1)	(16.2)	$ (0.2)
Subsidiaries [Member] | Electric Transmission [Member] | Dpandl Investment [Member]
Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	99.3		99.3
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	67.1		67.1
Subsidiaries [Member] | 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	11.1		11.1
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	160.3		160.3
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	88.6		$ 88.6
Subsidiaries [Member] | Total Jointly Owned Stations [Member] | Dpandl Share [Member]
Property, Plant and Equipment [Line Items]
Production Plan Capacity | MW			1,876
Subsidiaries [Member] | Conesville Unit Four [Member] | Dpandl Investment [Member]
Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	0.7		$ 0.7
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	0.6		0.6
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	$ 0.6		$ 0.6
Subsidiaries [Member] | Conesville Unit Four [Member] | Dpandl Share [Member]
Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	16.50%		16.50%
Production Plan Capacity | MW			129
Subsidiaries [Member] | 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		$ 0.0
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	8.4		8.4
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	$ 2.5		$ 2.5
Subsidiaries [Member] | Killen Station [Member] | Dpandl Share [Member]
Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	67.00%		67.00%
Production Plan Capacity | MW			402
Subsidiaries [Member] | Miami Fort Unit Seven And Eight [Member] | Dpandl Investment [Member]
Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	$ 5.1		$ 5.1
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	31.2		31.2
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	$ 3.1		$ 3.1
Subsidiaries [Member] | Miami Fort Unit Seven And Eight [Member] | Dpandl Share [Member]
Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	36.00%		36.00%
Production Plan Capacity | MW			368
Subsidiaries [Member] | Stuart Station [Member] | Dpandl Investment [Member]
Property, Plant and Equipment [Line Items]
Write off of net book value			$ 6.4
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	$ 0.0		0.0
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	0.9		0.9
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	$ 0.9		0.9
Gain (Loss) on Sale of Assets and Asset Impairment Charges			$ 3.2
Subsidiaries [Member] | Stuart Station [Member] | Dpandl Share [Member]
Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	35.00%		35.00%
Production Plan Capacity | MW			606
Subsidiaries [Member] | Zimmer Station [Member] | Dpandl Investment [Member]
Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	$ 5.3		$ 5.3
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	19.9		19.9
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	$ 14.4		$ 14.4
Subsidiaries [Member] | Zimmer Station [Member] | Dpandl Share [Member]
Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	28.10%		28.10%
Production Plan Capacity | MW			371
Subsidiaries [Member] | Miami Fort and Zimmer [Member]
Property, Plant and Equipment [Line Items]
Asset Retirement Obligation, Held for Sale	$ (3.7)		$ (3.7)
Subsidiaries [Member] | Miami Fort and Zimmer [Member] | Dpandl Investment [Member]
Property, Plant and Equipment [Line Items]
Sale of undivided interest in jointly-owned production units					$ 50.0

XML

Fair Value (Narrative) (Details) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Long-term debt, earliest maturities	2019
Long-term debt, latest maturities	2061
Unrealized gains in AOCI, before tax	$ 1.3
Unrealized Gains in AOCI, Net of Tax	0.9
Unrealized Gains and Immaterial Unrealized Losses in AOCI, Before Tax		$ 1.0
Unrealized gains and immaterial unrealized losses in AOCI, after tax		0.6
Realized gains on investments sold to facilitate the distribution of benefits	0.8
Realized gains on investments sold to facilitate the distribution of benefits, after tax	$ 0.5
Percent of inputs to the fair value of derivative instruments from quoted market prices (percent)	89.00%
Increase (Decrease) in Asset Retirement Obligations	$ 4.4
THE DAYTON POWER AND LIGHT COMPANY [Member]
Long-term debt, earliest maturities	2020
Long-term debt, latest maturities	2061
Unrealized gains in AOCI, before tax	$ 1.4
Unrealized Gains in AOCI, Net of Tax	0.9
Unrealized Gains and Immaterial Unrealized Losses in AOCI, Before Tax		1.1
Unrealized gains and immaterial unrealized losses in AOCI, after tax		$ 0.7
Realized gains on investments sold to facilitate the distribution of benefits	0.8
Realized gains on investments sold to facilitate the distribution of benefits, after tax	$ 0.5
Percent of inputs to the fair value of derivative instruments from quoted market prices (percent)	89.00%
Increase (Decrease) in Asset Retirement Obligations	$ 4.4

XML

Fair Value (Fair Value and Cost of Non-Derivative Instruments) (Details) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Realized gains on investments sold to facilitate the distribution of benefits, after tax	$ 0.5
Unrealized Gains in AOCI, Net of Tax	0.9
Unrealized Gains and Immaterial Unrealized Losses in AOCI, Before Tax		$ 1.0
THE DAYTON POWER AND LIGHT COMPANY [Member]
Realized gains on investments sold to facilitate the distribution of benefits, after tax	0.5
Unrealized Gains in AOCI, Net of Tax	0.9
Unrealized Gains and Immaterial Unrealized Losses in AOCI, Before Tax		1.1
Cost [Member]
Total Assets	7.4	7.6
Cost [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Assets	7.4	7.6
Fair Value [Member]
Total Master Trust Assets, Fair Value	8.8	8.7
Total Assets	8.8	8.7
Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	8.8	8.7
Total Assets	8.8	8.7
Money Market Funds [Member] | Cost [Member]
Total Master Trust Assets, Cost	0.4	0.4
Money Market Funds [Member] | Cost [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Cost	0.4	0.4
Money Market Funds [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	0.4	0.4
Money Market Funds [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.4	0.4
Equity Securities [Member] | Cost [Member]
Total Master Trust Assets, Cost	2.6	2.4
Equity Securities [Member] | Cost [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Cost	2.6	2.4
Equity Securities [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	3.9	3.4
Equity Securities [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	3.9	3.4
Debt Securities [Member] | Cost [Member]
Total Master Trust Assets, Cost	4.2	4.4
Debt Securities [Member] | Cost [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Cost	4.2	4.4
Debt Securities [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	4.3	4.4
Debt Securities [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	4.3	4.4
Hedge Funds [Member] | Cost [Member]
Total Master Trust Assets, Cost	0.1	0.0
Hedge Funds [Member] | Cost [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Cost	0.1	0.0
Hedge Funds [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	0.1	0.1
Hedge Funds [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.1	0.1
Real Estate Funds [Member] | Cost [Member]
Total Master Trust Assets, Cost	0.0	0.3
Real Estate Funds [Member] | Cost [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Cost	0.0	0.3
Real Estate Funds [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	0.0	0.3
Real Estate Funds [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.0	0.3
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	1,837.3	1,858.0
Debt [Member] | Cost [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt, Cost	739.6	749.0
Debt [Member] | Fair Value [Member]
Debt, Fair Value	1,926.2	1,907.7
Debt [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt, Fair Value	$ 753.0	$ 763.5

XML

Fair Value (Fair Value of Assets and Liabilities Measured on Recurring Basis) (Details) - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Level 1 [Member]
Total Master Trust Assets, Fair Value	$ 0.4	$ 0.4
Total Derivative Assets	0.3	0.0
Total Assets	0.7	0.4
Total Derivative Liabilities	1.0	0.0
Total Liabilities	1.0	0.0
Level 1 [Member] | Commodity Contract - FTR [Member]
Total Derivative Assets		0.0
Total Derivative Liabilities	0.0
Level 1 [Member] | Forward Contract Power [Member]
Total Derivative Assets	0.0	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	0.0	0.0
Level 1 [Member] | Natural Gas [Member]
Total Derivative Assets	0.3
Total Derivative Liabilities	1.0
Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.4	0.4
Total Derivative Assets	0.3	0.0
Total Assets	0.7	0.4
Total Derivative Liabilities	1.0	0.0
Total Liabilities	1.0	0.0
Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - FTR [Member]
Total Derivative Assets		0.0
Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member]
Total Derivative Assets	0.0	0.0
Total Derivative 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
Total Derivative Liabilities	0.0	0.0
Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Natural Gas [Member]
Total Derivative Assets	0.3
Total Derivative Liabilities	1.0
Level 2 [Member]
Total Master Trust Assets, Fair Value	8.4	8.3
Total Derivative Assets	17.3	20.7
Total Assets	25.7	29.0
Total Derivative Liabilities	10.0	26.7
Total Liabilities	1,918.4	1,916.4
Level 2 [Member] | Commodity Contract - FTR [Member]
Total Derivative Assets		0.0
Total Derivative Liabilities	0.0
Level 2 [Member] | Forward Contract Power [Member]
Total Derivative Assets	16.4	19.5
Total Derivative Liabilities	9.8	26.0
Level 2 [Member] | Interest Rate Contract [Member]
Total Derivative Assets	0.9	1.2
Total Derivative Liabilities	0.2	0.7
Level 2 [Member] | Natural Gas [Member]
Total Derivative Assets	0.0
Total Derivative Liabilities	0.0
Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	8.4	8.3
Total Derivative Assets	17.3	20.7
Total Assets	25.7	29.0
Total Derivative Liabilities	10.0	26.7
Total Liabilities	745.1	772.2
Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - FTR [Member]
Total Derivative Assets		0.0
Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member]
Total Derivative Assets	16.4	19.5
Total Derivative Liabilities	9.8	26.0
Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Interest Rate Contract [Member]
Total Derivative Assets	0.9	1.2
Total Derivative Liabilities	0.2	0.7
Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Natural Gas [Member]
Total Derivative Assets	0.0
Total Derivative Liabilities	0.0
Level 3 [Member]
Total Master Trust Assets, Fair Value	0.0	0.0
Total Derivative Assets	0.0	0.1
Total Assets	0.0	0.1
Total Derivative Liabilities	0.6	2.5
Total Liabilities	18.5	20.5
Level 3 [Member] | Commodity Contract - FTR [Member]
Total Derivative Assets		0.1
Total Derivative Liabilities	0.6
Level 3 [Member] | Forward Contract Power [Member]
Total Derivative Assets	0.0	0.0
Total Derivative Liabilities	0.0	2.5
Level 3 [Member] | Interest Rate Contract [Member]
Total Derivative Assets	0.0	0.0
Total Derivative Liabilities	0.0	0.0
Level 3 [Member] | Natural Gas [Member]
Total Derivative Assets	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	0.1
Total Assets	0.0	0.1
Total Derivative Liabilities	0.6	2.5
Total Liabilities	18.5	20.5
Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - FTR [Member]
Total Derivative Assets		0.1
Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member]
Total Derivative Assets	0.0	0.0
Total Derivative Liabilities	0.0	2.5
Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Interest Rate Contract [Member]
Total Derivative Assets	0.0	0.0
Total Derivative Liabilities	0.0	0.0
Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Natural Gas [Member]
Total Derivative Assets	0.0
Total Derivative Liabilities	0.0
Fair Value [Member]
Total Master Trust Assets, Fair Value	8.8	8.7
Total Derivative Assets	17.6	20.8
Total Assets	26.4	29.5
Total Derivative Liabilities	11.6	29.2
Total Liabilities	1,937.9	1,936.9
Fair Value [Member] | Commodity Contract - FTR [Member]
Total Derivative Assets		0.1
Total Derivative Liabilities	0.6
Fair Value [Member] | Forward Contract Power [Member]
Total Derivative Assets	16.4	19.5
Total Derivative Liabilities	9.8	28.5
Fair Value [Member] | Interest Rate Contract [Member]
Total Derivative Assets	0.9	1.2
Total Derivative Liabilities	0.2	0.7
Fair Value [Member] | Natural Gas [Member]
Total Derivative Assets	0.3
Total Derivative Liabilities	1.0
Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	8.8	8.7
Total Derivative Assets	17.6	20.8
Total Assets	26.4	29.5
Total Derivative Liabilities	11.6	29.2
Total Liabilities	764.6	792.7
Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - FTR [Member]
Total Derivative Assets		0.1
Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member]
Total Derivative Assets	16.4	19.5
Total Derivative Liabilities	9.8	28.5
Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Interest Rate Contract [Member]
Total Derivative Assets	0.9	1.2
Total Derivative Liabilities	0.2	0.7
Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Natural Gas [Member]
Total Derivative Assets	0.3
Total Derivative Liabilities	1.0
Money Market Funds [Member] | Level 1 [Member]
Total Master Trust Assets, Fair Value	0.4	0.4
Money Market Funds [Member] | Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.4	0.4
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	0.4	0.4
Money Market Funds [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.4	0.4
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	3.9	3.4
Equity Securities [Member] | Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	3.9	3.4
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	3.9	3.4
Equity Securities [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	3.9	3.4
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	4.3	4.4
Debt Securities [Member] | Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	4.3	4.4
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	4.3	4.4
Debt Securities [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	4.3	4.4
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	0.1	0.1
Hedge Funds [Member] | Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.1	0.1
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	0.1	0.1
Hedge Funds [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.1	0.1
Real Estate Funds [Member] | Level 1 [Member]
Total Master Trust Assets, Fair Value		0.0
Real Estate Funds [Member] | Level 1 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value		0.0
Real Estate Funds [Member] | Level 2 [Member]
Total Master Trust Assets, Fair Value		0.3
Real Estate Funds [Member] | Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value		0.3
Real Estate Funds [Member] | Level 3 [Member]
Total Master Trust Assets, Fair Value		0.0
Real Estate Funds [Member] | Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value		0.0
Real Estate Funds [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	0.0	0.3
Real Estate Funds [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Total Master Trust Assets, Fair Value	0.0	0.3
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	1,908.4	1,889.7
Debt [Member] | Level 2 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt	735.1	745.5
Debt [Member] | Level 3 [Member]
Debt	17.9	18.0
Debt [Member] | Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt	17.9	18.0
Debt [Member] | Fair Value [Member]
Debt	1,926.3	1,907.7
Debt [Member] | Fair Value [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt	$ 753.0	$ 763.5

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		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Increase (Decrease) in Asset Retirement Obligations			$ 4.4
Property, Plant and Equipment, Net	$ 1,659.6		1,659.6		$ 1,767.2
Impairment of Long-Lived Assets Held-for-use	0.0	$ 235.5	66.4	$ 235.5
Peaking Generating Facilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant and Equipment, Net		9.9		9.9
Impairment of Long-Lived Assets Held-for-use				4.7
Peaking Generating Facilities [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant, and Equipment, Fair Value Disclosure		0.0		0.0
Peaking Generating Facilities [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		0.0
Peaking Generating Facilities [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant, and Equipment, Fair Value Disclosure		5.2		5.2
Killen [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant and Equipment, Net	35.2	315.1	35.2	315.1
Impairment of Long-Lived Assets Held-for-use			27.3	230.8
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	0.0	0.0	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	0.0	0.0	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	84.3	7.9	84.3
Stuart [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant and Equipment, Net	42.4		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		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		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		3.3
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			4.4
Property, Plant and Equipment, Net	1,334.5		1,334.5		$ 1,440.6
Impairment of Long-Lived Assets Held-for-use	0.0	857.1	66.3	857.1
THE DAYTON POWER AND LIGHT COMPANY [Member] | Zimmer [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant and Equipment, Net		429.9		429.9
Impairment of Long-Lived Assets Held-for-use				318.9
THE DAYTON POWER AND LIGHT COMPANY [Member] | Zimmer [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		0.0
THE DAYTON POWER AND LIGHT COMPANY [Member] | Zimmer [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		0.0
THE DAYTON POWER AND LIGHT COMPANY [Member] | Zimmer [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant, and Equipment, Fair Value Disclosure		111.0		111.0
THE DAYTON POWER AND LIGHT COMPANY [Member] | Killen [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant and Equipment, Net	35.2	330.5	35.2	330.5
Impairment of Long-Lived Assets Held-for-use			27.3	246.2
THE DAYTON POWER AND LIGHT COMPANY [Member] | 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	0.0	0.0	0.0
THE DAYTON POWER AND LIGHT COMPANY [Member] | 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	0.0	0.0	0.0
THE DAYTON POWER AND LIGHT COMPANY [Member] | 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	84.3	7.9	84.3
THE DAYTON POWER AND LIGHT COMPANY [Member] | Stuart [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant and Equipment, Net	42.3	456.4	42.3	456.4
Impairment of Long-Lived Assets Held-for-use			39.0	292.0
THE DAYTON POWER AND LIGHT COMPANY [Member] | 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	0.0	0.0	0.0
THE DAYTON POWER AND LIGHT COMPANY [Member] | 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	0.0	0.0	0.0
THE DAYTON POWER AND LIGHT COMPANY [Member] | 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	$ 164.4	$ 3.3	$ 164.4
Income Approach Valuation Technique [Member] | Weighted Average [Member] | Peaking Generating Facilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent				(4.00%)
Fair Value Inputs, Discount Rate				7.00%
Fair Value Inputs, Long-term Revenue Growth Rate				(3.00%)
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%	6.00%
Fair Value Inputs, Discount Rate			7.00%	11.00%
Fair Value Inputs, Long-term Revenue Growth Rate				2.00%
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%
Income Approach Valuation Technique [Member] | Weighted Average [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Zimmer [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent				4.00%
Fair Value Inputs, Discount Rate				9.00%
Fair Value Inputs, Long-term Revenue Growth Rate				1.00%
Income Approach Valuation Technique [Member] | Weighted Average [Member] | THE DAYTON POWER AND LIGHT COMPANY [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%	6.00%
Fair Value Inputs, Discount Rate			7.00%	11.00%
Fair Value Inputs, Long-term Revenue Growth Rate				2.00%
Income Approach Valuation Technique [Member] | Weighted Average [Member] | THE DAYTON POWER AND LIGHT COMPANY [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%	5.00%
Fair Value Inputs, Discount Rate			7.00%	9.00%
Fair Value Inputs, Long-term Revenue Growth Rate				2.00%
Income Approach Valuation Technique [Member] | Minimum [Member] | Peaking Generating Facilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent				(29.00%)
Fair Value Inputs, Long-term Revenue Growth Rate				(22.00%)
Income Approach Valuation Technique [Member] | Minimum [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				(50.00%)
Fair Value Inputs, Long-term Revenue Growth Rate				(11.00%)
Income Approach Valuation Technique [Member] | Minimum [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Zimmer [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent				(46.00%)
Fair Value Inputs, Long-term Revenue Growth Rate				(14.00%)
Income Approach Valuation Technique [Member] | Minimum [Member] | THE DAYTON POWER AND LIGHT COMPANY [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				(50.00%)
Fair Value Inputs, Long-term Revenue Growth Rate				(11.00%)
Income Approach Valuation Technique [Member] | Minimum [Member] | THE DAYTON POWER AND LIGHT COMPANY [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				(29.00%)
Fair Value Inputs, Long-term Revenue Growth Rate				(9.00%)
Income Approach Valuation Technique [Member] | Maximum [Member] | Peaking Generating Facilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent				24.00%
Fair Value Inputs, Long-term Revenue Growth Rate				17.00%
Income Approach Valuation Technique [Member] | Maximum [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				67.00%
Fair Value Inputs, Long-term Revenue Growth Rate				13.00%
Income Approach Valuation Technique [Member] | Maximum [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Zimmer [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Long-term Pre-tax Operating Margin, Percent				80.00%
Fair Value Inputs, Long-term Revenue Growth Rate				13.00%
Income Approach Valuation Technique [Member] | Maximum [Member] | THE DAYTON POWER AND LIGHT COMPANY [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				67.00%
Fair Value Inputs, Long-term Revenue Growth Rate				13.00%
Income Approach Valuation Technique [Member] | Maximum [Member] | THE DAYTON POWER AND LIGHT COMPANY [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				52.00%
Fair Value Inputs, Long-term Revenue Growth Rate				10.00%
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			$ 2.4	$ 2.3
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			$ 1.6	$ 2.3

XML

Derivative Instruments and Hedging Activities (Narrative) (Details)	Jun. 30, 2017 USD ($) Number_of_interest_rate_swaps	Dec. 31, 2016 USD ($)
Fair value of commodity derivative instruments	$ 11,600,000
Collateral Already Posted, Aggregate Fair Value	800,000
Liability position offset by the asset position of counterparties with master netting agreements	9,400,000
Collateral if debt were to fall below investment grade	$ 1,400,000
THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument, Number of Financial Covenants | Number_of_interest_rate_swaps	2
Fair value of commodity derivative instruments	$ 11,600,000
Collateral Already Posted, Aggregate Fair Value	800,000
Liability position offset by the asset position of counterparties with master netting agreements	9,400,000
Collateral if debt were to fall below investment grade	1,400,000
One Point One Three To One Point One Seven Bonds Maturing In August Two Thousand Twenty [Member]
Long-term Debt, Gross	200,000,000
One Point One Three To One Point One Seven Bonds Maturing In August Two Thousand Twenty [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Long-term Debt, Gross	200,000,000
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]
Derivative, Notional Amount, Purchase (Sales), Net	200,000,000	$ 200,000,000
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Derivative, Notional Amount, Purchase (Sales), Net	$ 200,000,000	$ 200,000,000

XML

Derivative Instruments and Hedging Activities (Outstanding Derivative Instruments) (Details)	Jun. 30, 2017 USD ($) MMBTU MWh	Dec. 31, 2016 USD ($) MMBTU MWh
Not Designated as Hedging Instrument [Member] | Commodity Contract - FTR [Member]
Purchase of Units Derivative Instruments Financial Transmission Rights	4,700	2,300
Sale of Units Derivative Instruments Financial Transmission Rights	0	0
Derivative, Nonmonetary Notional Amount MWh	4,700	2,300
Not Designated as Hedging Instrument [Member] | Natural Gas [Member]
Purchase of Units Derivative Instruments Natural Gas | MMBTU	18,490,000	1,590,000
Sale of Units Derivative Instruments Natural Gas | MMBTU	(703,200)	0
Derivative, Nonmonetary Notional Amount MWh | MMBTU	17,786,800	1,590,000
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member]
Purchase of Units Derivative Instruments Forward Power Contracts Not Designated as Hedged	1,426,000	2,568,300
Sales of Units Derivative Instruments Forward Power Contracts Not Designated as Hedged	(1,630,500)	(2,020,900)
Derivative, Nonmonetary Notional Amount MWh	(204,500)	547,400
Not Designated as Hedging Instrument [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - FTR [Member]
Purchase of Units Derivative Instruments Financial Transmission Rights	4,700	2,300
Sale of Units Derivative Instruments Financial Transmission Rights	0	0
Derivative, Nonmonetary Notional Amount MWh	4,700	2,300
Not Designated as Hedging Instrument [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Natural Gas [Member]
Purchase of Units Derivative Instruments Natural Gas | MMBTU	18,490,000	1,590,000
Sale of Units Derivative Instruments Natural Gas | MMBTU	(703,200)	0
Derivative, Nonmonetary Notional Amount MWh | MMBTU	17,786,800	1,590,000
Not Designated as Hedging Instrument [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member]
Purchase of Units Derivative Instruments Forward Power Contracts Not Designated as Hedged	1,426,000	2,568,300
Sales of Units Derivative Instruments Forward Power Contracts Not Designated as Hedged	(1,630,500)	(2,037,500)
Derivative, Nonmonetary Notional Amount MWh	(204,500)	530,800
Designated as Hedging Instrument [Member] | Forward Contract Power [Member]
Purchase of Units Derivative Instruments Forward Power Contracts Designated as Cash Flow Hedge	810,500	342,900
Sales of Units Derivative Instruments Forward Power Contracts Designated as Cash Flow Hedge	(4,014,200)	(9,974,500)
Derivative, Nonmonetary Notional Amount MWh	(3,203,700)	(9,631,600)
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Purchase of Derivative Instruments Interest Rate Swap | $	$ 200,000,000	$ 200,000,000
Sale of Derivative Instruments Interest Rate Swap | $	0	0
Derivative, Notional Amount, Purchase (Sales), Net | $	$ 200,000,000	$ 200,000,000
Designated as Hedging Instrument [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member]
Purchase of Units Derivative Instruments Forward Power Contracts Designated as Cash Flow Hedge	810,500	342,900
Sales of Units Derivative Instruments Forward Power Contracts Designated as Cash Flow Hedge	(4,014,200)	(9,974,500)
Derivative, Nonmonetary Notional Amount MWh	(3,203,700)	(9,631,600)
Designated as Hedging Instrument [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Interest Rate Swap [Member]
Purchase of Derivative Instruments Interest Rate Swap | $	$ 200,000,000	$ 200,000,000
Sale of Derivative Instruments Interest Rate Swap | $	0	0
Derivative, Notional Amount, Purchase (Sales), Net | $	$ 200,000,000	$ 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		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Forward Contract Power [Member]
Accumulated Derivative Gain/Loss in AOCI [Roll Forward]
Beginning accumulated derivative gain / (loss) in AOCI	$ 1.8	$ 22.5	$ (4.3)	$ 9.2
Net gains / (losses) associated with current period hedging transactions	1.2	(8.5)	6.0	13.0
Ending accumulated derivative gain / (loss) in AOCI	3.0	3.4	3.0	3.4
Portion expected to be reclassified to earnings in the next twelve months	3.2		$ 3.2
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)			9 months
Interest Rate Contract [Member]
Accumulated Derivative Gain/Loss in AOCI [Roll Forward]
Beginning accumulated derivative gain / (loss) in AOCI	17.5	17.5	$ 17.4	17.5
Net gains / (losses) associated with current period hedging transactions	(0.1)	0.0	0.1	0.0
Ending accumulated derivative gain / (loss) in AOCI	17.2	17.3	17.2	17.3
Portion expected to be reclassified to earnings in the next twelve months	(0.6)		$ (0.6)
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)			38 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	1.8	22.5	$ (4.3)	9.2
Net gains / (losses) associated with current period hedging transactions	1.2	(8.5)	6.0	13.0
Ending accumulated derivative gain / (loss) in AOCI	3.0	3.4	3.0	3.4
Portion expected to be reclassified to earnings in the next twelve months	3.2		$ 3.2
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)			9 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	1.7	1.8	$ 1.6	2.0
Net gains / (losses) associated with current period hedging transactions	(0.1)	0.0	0.2	0.0
Ending accumulated derivative gain / (loss) in AOCI	1.4	1.6	1.4	1.6
Portion expected to be reclassified to earnings in the next twelve months	(0.8)		$ (0.8)
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)			38 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	$ 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	(0.2)	(0.2)	(0.3)	(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	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	(0.2)	(0.2)	(0.4)	(0.4)
Revenue [Member] | Forward Contract Power [Member]
Accumulated Derivative Gain/Loss in AOCI [Roll Forward]
Net gains losses reclassified to earnings	0.0	(13.0)	(0.8)	(24.0)
Revenue [Member] | Interest Rate Contract [Member]
Accumulated Derivative Gain/Loss in AOCI [Roll Forward]
Net gains losses reclassified to earnings	0.0	0.0	0.0	0.0
Revenue [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	(13.0)	(0.8)	(24.0)
Revenue [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	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	0.0	2.4	2.1	5.2
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	0.0	0.0
Purchased Power [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	2.4	2.1	5.2
Purchased Power [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	$ 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		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Change in unrealized gain / (loss)	$ 2.4	$ 3.3	$ 2.2	$ 1.9
Realized gain / (loss)	(0.6)	(1.5)	(3.2)	(2.0)
Derivative, Gain (Loss) on Derivative, Net	1.8	1.8	(1.0)	(0.1)
Commodity Contract - FTR [Member]
Change in unrealized gain / (loss)	(0.7)	0.2	(0.7)	0.4
Realized gain / (loss)	0.1	0.2	0.3	0.4
Derivative, Gain (Loss) on Derivative, Net	(0.6)	0.4	(0.4)	0.8
Forward Contract Power [Member]
Change in unrealized gain / (loss)	3.7	2.6	3.6	1.2
Realized gain / (loss)	(0.7)	(2.4)	(3.3)	(2.9)
Derivative, Gain (Loss) on Derivative, Net	3.0	0.2	0.3	(1.7)
Natural Gas [Member]
Change in unrealized gain / (loss)	(0.6)	0.5	(0.7)	0.3
Realized gain / (loss)	0.0	0.7	(0.2)	0.5
Derivative, Gain (Loss) on Derivative, Net	(0.6)	1.2	(0.9)	0.8
THE DAYTON POWER AND LIGHT COMPANY [Member]
Change in unrealized gain / (loss)	2.4	3.5	2.2	1.6
Realized gain / (loss)	(0.6)	(1.4)	(3.3)	(1.8)
Derivative, Gain (Loss) on Derivative, Net	1.8	2.1	(1.1)	(0.2)
THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - FTR [Member]
Change in unrealized gain / (loss)	(0.7)	0.2	(0.7)	0.4
Realized gain / (loss)	0.1	0.2	0.3	0.4
Derivative, Gain (Loss) on Derivative, Net	(0.6)	0.4	(0.4)	0.8
THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member]
Change in unrealized gain / (loss)	3.7	2.8	3.6	0.9
Realized gain / (loss)	(0.7)	(2.3)	(3.4)	(2.7)
Derivative, Gain (Loss) on Derivative, Net	3.0	0.5	0.2	(1.8)
THE DAYTON POWER AND LIGHT COMPANY [Member] | Natural Gas [Member]
Change in unrealized gain / (loss)	(0.6)	0.5	(0.7)	0.3
Realized gain / (loss)	0.0	0.7	(0.2)	0.5
Derivative, Gain (Loss) on Derivative, Net	(0.6)	1.2	(0.9)	0.8
Revenue [Member]
Derivative, Gain (Loss) on Derivative, Net	(1.0)	(5.3)	(6.5)	(6.6)
Revenue [Member] | Commodity Contract - FTR [Member]
Derivative, Gain (Loss) on Derivative, Net	0.0	0.0	0.0	0.0
Revenue [Member] | Forward Contract Power [Member]
Derivative, Gain (Loss) on Derivative, Net	(1.0)	(5.3)	(6.5)	(6.6)
Revenue [Member] | Natural Gas [Member]
Derivative, Gain (Loss) on Derivative, Net	0.0	0.0	0.0	0.0
Revenue [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Derivative, Gain (Loss) on Derivative, Net	(1.1)	(5.1)	(6.6)	(6.6)
Revenue [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - FTR [Member]
Derivative, Gain (Loss) on Derivative, Net	0.0	0.0	0.0	0.0
Revenue [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member]
Derivative, Gain (Loss) on Derivative, Net	(1.1)	(5.1)	(6.6)	(6.6)
Revenue [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Natural Gas [Member]
Derivative, Gain (Loss) on Derivative, Net	0.0	0.0	0.0	0.0
Purchased Power [Member]
Derivative, Gain (Loss) on Derivative, Net	2.8	7.1	5.5	6.5
Purchased Power [Member] | Commodity Contract - FTR [Member]
Derivative, Gain (Loss) on Derivative, Net	(0.6)	0.4	(0.4)	0.8
Purchased Power [Member] | Forward Contract Power [Member]
Derivative, Gain (Loss) on Derivative, Net	4.0	5.5	6.8	4.9
Purchased Power [Member] | Natural Gas [Member]
Derivative, Gain (Loss) on Derivative, Net	(0.6)	1.2	(0.9)	0.8
Purchased Power [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Derivative, Gain (Loss) on Derivative, Net	2.9	7.2	5.5	6.4
Purchased Power [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Commodity Contract - FTR [Member]
Derivative, Gain (Loss) on Derivative, Net	(0.6)	0.4	(0.4)	0.8
Purchased Power [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Forward Contract Power [Member]
Derivative, Gain (Loss) on Derivative, Net	4.1	5.6	6.8	4.8
Purchased Power [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Natural Gas [Member]
Derivative, Gain (Loss) on Derivative, Net	$ (0.6)	$ 1.2	$ (0.9)	$ 0.8

XML

Derivative Instruments and Hedging Activities (Fair Value and Balance Sheet Location (Details) - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Derivative Liability, Fair Value	$ 11.6
Liability position offset by the asset position of counterparties with master netting agreements	9.4
THE DAYTON POWER AND LIGHT COMPANY [Member]
Derivative Liability, Fair Value	11.6
Liability position offset by the asset position of counterparties with master netting agreements	9.4
Total Assets [Member]
Derivative Asset, Fair Value	17.6	$ 20.8
Derivative, Collateral, Obligation to Return Securities	(9.4)	(16.8)
Derivative, Collateral, Obligation to Return Cash	0.0	0.0
Derivative Asset, Fair Value, Amount Offset Against Collateral	8.2	4.0
Total Assets [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Derivative Asset, Fair Value	17.6	20.8
Derivative, Collateral, Obligation to Return Securities	(9.4)	(16.8)
Derivative, Collateral, Obligation to Return Cash	0.0	0.0
Derivative Asset, Fair Value, Amount Offset Against Collateral	8.2	4.0
Total Liabilities [Member]
Derivative Liability, Fair Value	11.6	29.2
Derivative, Collateral, Right to Reclaim Securities	(9.4)	(16.8)
Derivative, Collateral, Right to Reclaim Cash	(0.8)	(6.3)
Liability position offset by the asset position of counterparties with master netting agreements	1.4	6.1
Total Liabilities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Derivative Liability, Fair Value	11.6	29.2
Derivative, Collateral, Right to Reclaim Securities	(9.4)	(16.8)
Derivative, Collateral, Right to Reclaim Cash	(0.8)	(6.3)
Liability position offset by the asset position of counterparties with master netting agreements	1.4	6.1
Cash Flow Hedging [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Prepayments and Current Assets [Member]
Derivative Asset, Fair Value	10.2	11.0
Derivative, Collateral, Obligation to Return Securities	(5.0)	(10.5)
Derivative, Collateral, Obligation to Return Cash	0.0	0.0
Derivative Asset, Fair Value, Amount Offset Against Collateral	5.2	0.5
Cash Flow Hedging [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Prepayments and Current Assets [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Derivative Asset, Fair Value	10.2	11.0
Derivative, Collateral, Obligation to Return Securities	(5.0)	(10.5)
Derivative, Collateral, Obligation to Return Cash	0.0	0.0
Derivative Asset, Fair Value, Amount Offset Against Collateral	5.2	0.5
Cash Flow Hedging [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member]
Derivative Liability, Fair Value	5.3	16.4
Derivative, Collateral, Right to Reclaim Securities	(5.0)	(10.5)
Derivative, Collateral, Right to Reclaim Cash	0.0	(5.5)
Liability position offset by the asset position of counterparties with master netting agreements	0.3	0.4
Cash Flow Hedging [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Derivative Liability, Fair Value	5.3	16.4
Derivative, Collateral, Right to Reclaim Securities	(5.0)	(10.5)
Derivative, Collateral, Right to Reclaim Cash	0.0	(5.5)
Liability position offset by the asset position of counterparties with master netting agreements	0.3	0.4
Cash Flow 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		(0.6)
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] | Long-term Derivative Positions [Member] | Other Deferred Asset [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Derivative Asset, Fair Value		0.6
Derivative, Collateral, Obligation to Return Securities		(0.6)
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] | Long-term Derivative Positions [Member] | Other Deferred Credit [Member]
Derivative Liability, Fair Value		2.4
Derivative, Collateral, Right to Reclaim Securities		(0.6)
Derivative, Collateral, Right to Reclaim Cash		(0.8)
Liability position offset by the asset position of counterparties with master netting agreements		1.0
Cash Flow Hedging [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Credit [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Derivative Liability, Fair Value		2.4
Derivative, Collateral, Right to Reclaim Securities		(0.6)
Derivative, Collateral, Right to Reclaim Cash		(0.8)
Liability position offset by the asset position of counterparties with master netting agreements		1.0
Cash Flow Hedging [Member] | Natural Gas Futures [Member] | Long-term Derivative Positions [Member] | Other Deferred Asset [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Derivative Asset, Fair Value	0.2
Derivative, Collateral, Obligation to Return Securities	(0.2)
Derivative, Collateral, Obligation to Return Cash	0.0
Derivative Asset, Fair Value, Amount Offset Against Collateral	0.0
Cash Flow Hedging [Member] | Interest Rate Swap [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member]
Derivative Liability, Fair Value		0.7
Derivative, Collateral, Right to Reclaim Securities		0.0
Derivative, Collateral, Right to Reclaim Cash		0.0
Liability position offset by the asset position of counterparties with master netting agreements		0.7
Cash Flow Hedging [Member] | Interest Rate Swap [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Derivative Liability, Fair Value		0.7
Derivative, Collateral, Right to Reclaim Securities		0.0
Derivative, Collateral, Right to Reclaim Cash		0.0
Liability position offset by the asset position of counterparties with master netting agreements		0.7
Cash Flow Hedging [Member] | Interest Rate Swap [Member] | Long-term Derivative Positions [Member] | Other Deferred Asset [Member]
Derivative Asset, Fair Value	0.9	1.2
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	0.9	1.2
Cash Flow Hedging [Member] | Interest Rate Swap [Member] | Long-term Derivative Positions [Member] | Other Deferred Asset [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Derivative Asset, Fair Value	0.9	1.2
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	0.9	1.2
Fair Value Hedging [Member] | Commodity Contract - FTR [Member] | Short-term Derivative Positions [Member] | Other Prepayments and Current Assets [Member]
Derivative Asset, Fair Value		0.1
Derivative, Collateral, Obligation to Return Securities		0.0
Derivative, Collateral, Obligation to Return Cash		0.0
Derivative Asset, Fair Value, Amount Offset Against Collateral		0.1
Fair Value Hedging [Member] | Commodity Contract - FTR [Member] | Short-term Derivative Positions [Member] | Other Prepayments and Current Assets [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Derivative Asset, Fair Value		0.1
Derivative, Collateral, Obligation to Return Securities		0.0
Derivative, Collateral, Obligation to Return Cash		0.0
Derivative Asset, Fair Value, Amount Offset Against Collateral		0.1
Fair Value Hedging [Member] | Commodity Contract - FTR [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member]
Derivative Liability, Fair Value	0.6
Derivative, Collateral, Right to Reclaim Securities	0.0
Derivative, Collateral, Right to Reclaim Cash	0.0
Liability position offset by the asset position of counterparties with master netting agreements	0.6
Fair Value Hedging [Member] | Commodity Contract - FTR [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Derivative Liability, Fair Value	0.6
Derivative, Collateral, Right to Reclaim Securities	0.0
Derivative, Collateral, Right to Reclaim Cash	0.0
Liability position offset by the asset position of counterparties with master netting agreements	0.6
Fair Value Hedging [Member] | Natural Gas [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member]
Derivative Liability, Fair Value	0.7
Derivative, Collateral, Right to Reclaim Securities	0.0
Derivative, Collateral, Right to Reclaim Cash	(0.7)
Liability position offset by the asset position of counterparties with master netting agreements	0.0
Fair Value Hedging [Member] | Natural Gas [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Derivative Liability, Fair Value	0.7
Derivative, Collateral, Right to Reclaim Securities	0.0
Derivative, Collateral, Right to Reclaim Cash	(0.7)
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	5.1	6.0
Derivative, Collateral, Obligation to Return Securities	(4.2)	(4.7)
Derivative, Collateral, Obligation to Return Cash	0.0	0.0
Derivative Asset, Fair Value, Amount Offset Against Collateral	0.9	1.3
Fair Value Hedging [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Prepayments and Current Assets [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Derivative Asset, Fair Value	5.1	6.0
Derivative, Collateral, Obligation to Return Securities	(4.2)	(4.7)
Derivative, Collateral, Obligation to Return Cash	0.0	0.0
Derivative Asset, Fair Value, Amount Offset Against Collateral	0.9	1.3
Fair Value Hedging [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member]
Derivative Liability, Fair Value	4.5	7.7
Derivative, Collateral, Right to Reclaim Securities	(4.2)	(4.7)
Derivative, Collateral, Right to Reclaim Cash	0.0	0.0
Liability position offset by the asset position of counterparties with master netting agreements	0.3	3.0
Fair Value Hedging [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Derivative Liability, Fair Value	4.5	7.7
Derivative, Collateral, Right to Reclaim Securities	(4.2)	(4.7)
Derivative, Collateral, Right to Reclaim Cash	0.0	0.0
Liability position offset by the asset position of counterparties with master netting agreements	0.3	3.0
Fair Value Hedging [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Asset [Member]
Derivative Asset, Fair Value	1.1	1.9
Derivative, Collateral, Obligation to Return Securities	0.0	(1.0)
Derivative, Collateral, Obligation to Return Cash	0.0	0.0
Derivative Asset, Fair Value, Amount Offset Against Collateral	1.1	0.9
Fair Value Hedging [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Asset [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Derivative Asset, Fair Value	1.1	1.9
Derivative, Collateral, Obligation to Return Securities	0.0	(1.0)
Derivative, Collateral, Obligation to Return Cash	0.0	0.0
Derivative Asset, Fair Value, Amount Offset Against Collateral	1.1	0.9
Fair Value Hedging [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Credit [Member]
Derivative Liability, Fair Value		2.0
Derivative, Collateral, Right to Reclaim Securities		(1.0)
Derivative, Collateral, Right to Reclaim Cash		0.0
Liability position offset by the asset position of counterparties with master netting agreements		1.0
Fair Value Hedging [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Credit [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Derivative Liability, Fair Value		2.0
Derivative, Collateral, Right to Reclaim Securities		(1.0)
Derivative, Collateral, Right to Reclaim Cash		0.0
Liability position offset by the asset position of counterparties with master netting agreements		$ 1.0
Fair Value Hedging [Member] | Natural Gas Futures [Member] | Short-term Derivative Positions [Member] | Other Prepayments and Current Assets [Member]
Derivative Asset, Fair Value	0.1
Derivative, Collateral, Obligation to Return Securities	0.0
Derivative, Collateral, Obligation to Return Cash	0.0
Derivative Asset, Fair Value, Amount Offset Against Collateral	0.1
Fair Value Hedging [Member] | Natural Gas Futures [Member] | Short-term Derivative Positions [Member] | Other Prepayments and Current Assets [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Derivative Asset, Fair Value	0.1
Derivative, Collateral, Obligation to Return Securities	0.0
Derivative, Collateral, Obligation to Return Cash	0.0
Derivative Asset, Fair Value, Amount Offset Against Collateral	0.1
Fair Value Hedging [Member] | Natural Gas Futures [Member] | Long-term Derivative Positions [Member] | Other Deferred Asset [Member]
Derivative Asset, Fair Value	0.2
Derivative, Collateral, Obligation to Return Securities	(0.2)
Derivative, Collateral, Obligation to Return Cash	0.0
Derivative Asset, Fair Value, Amount Offset Against Collateral	0.0
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member]
Derivative Liability, Fair Value	0.2
Derivative, Collateral, Right to Reclaim Securities	0.0
Derivative, Collateral, Right to Reclaim Cash	0.0
Liability position offset by the asset position of counterparties with master netting agreements	0.2
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Derivative Liability, Fair Value	0.2
Derivative, Collateral, Right to Reclaim Securities	0.0
Derivative, Collateral, Right to Reclaim Cash	0.0
Liability position offset by the asset position of counterparties with master netting agreements	0.2
Not Designated as Hedging Instrument [Member] | Natural Gas Futures [Member] | Long-term Derivative Positions [Member] | Other Deferred Credit [Member]
Derivative Liability, Fair Value	0.3
Derivative, Collateral, Right to Reclaim Securities	(0.2)
Derivative, Collateral, Right to Reclaim Cash	(0.1)
Liability position offset by the asset position of counterparties with master netting agreements	0.0
Not Designated as Hedging Instrument [Member] | Natural Gas Futures [Member] | Long-term Derivative Positions [Member] | Other Deferred Credit [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Derivative Liability, Fair Value	0.3
Derivative, Collateral, Right to Reclaim Securities	(0.2)
Derivative, Collateral, Right to Reclaim Cash	(0.1)
Liability position offset by the asset position of counterparties with master netting agreements	$ 0.0

XML

Debt (Narrative) (Details)			6 Months Ended		12 Months Ended
	Aug. 07, 2017 USD ($)	Jun. 23, 2017 USD ($)	Jun. 30, 2017 USD ($) fiscal_quarter debt_covenant	Jun. 30, 2016 USD ($)	Jun. 30, 2018 USD ($)	Dec. 31, 2016 USD ($)
Debt Instrument [Line Items]
Retirement of long-term debt			$ 22,800,000	$ 75,400,000
Total Debt to Total Capitalization Ratio			0.52
THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Retirement of long-term debt			$ 10,300,000	$ 0
Total Debt to Total Capitalization Ratio			0.52
Four Point Eight Zero Percentage Of Bonds Maturing In September Two Thousand Thirty Six [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount		$ 8,100,000
Long-term Debt, Gross			$ 91,900,000			$ 100,000,000
Debt instrument interest percentage			4.80%
Four Point Eight Zero Percentage Of Bonds Maturing In September Two Thousand Thirty Six [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount		$ 8,100,000
Long-term Debt, Gross			$ 91,900,000			100,000,000
Debt instrument interest percentage			4.80%
Term Loan Maturing 2022 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross			$ 442,800,000			445,000,000
Term Loan Maturing 2022 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross			$ 442,800,000			$ 445,000,000
Revolving Credit Agreement and Standby Letters of Credit [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Number of financial covenants | debt_covenant			2
Number of prior quarters included in 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
Subsequent Event [Member]
Debt Instrument [Line Items]
Long Term Indebtedness, Less than or Equal to					$ 750,000,000.0
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
Subsequent Event [Member] | Four Point Eight Zero Percentage Of Bonds Maturing In September Two Thousand Thirty Six [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount	$ 21,900,000
Long-term Debt, Gross	70,000,000
Subsequent Event [Member] | Four Point Eight Zero Percentage Of Bonds Maturing In September Two Thousand Thirty Six [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount	21,900,000
Long-term Debt, Gross	$ 70,000,000

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Debt (Long-term Debt) (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2017	Aug. 07, 2017	Dec. 31, 2016	Jun. 30, 2016
Debt Instrument [Line Items]
Capital Lease Obligations	$ 0.3		$ 0.4
Unamortized deferred finance costs	(10.0)		(10.7)
Unamortized deferred finance costs	(7.7)		(8.8)
Unamortized long-term debt discounts and premiums, net	(0.6)		(0.6)
Total long-term debt at subsidiary	737.8		747.2
Total long-term debt	1,837.6		1,858.4
Less: current portion	(50.9)		(29.7)
Long-term debt	$ 1,786.7		1,828.7
Long-term debt, earliest maturities	2019
Long-term debt, latest maturities	2061
THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Capital Lease Obligations	$ 0.3		0.4
Unamortized deferred finance costs	(11.0)		(11.8)
Unamortized long-term debt discounts and premiums, net	(5.1)		(5.5)
Unamortized long-term debt discounts	(2.0)		(2.2)
Total long-term debt	739.9		749.4
Less: current portion	(26.4)		(4.7)
Long-term debt	$ 713.5		744.7
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	$ 442.8		445.0
Term Loan Maturing 2022 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	442.8		445.0
Four Point Eight Zero Percentage Of Bonds Maturing In September Two Thousand Thirty Six [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 91.9		100.0
Debt instrument maturity year	Sep. 01, 2036
Debt instrument interest percentage	4.80%
Four Point Eight Zero Percentage Of Bonds Maturing In September Two Thousand Thirty Six [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 91.9		100.0
Debt instrument maturity year	Sep. 01, 2036
Debt instrument interest percentage	4.80%
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	$ 200.0		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	$ 17.9		18.0
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	$ 17.9		18.0
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	$ 112.5		125.0
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
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] | Four Point Eight Zero Percentage Of Bonds Maturing In September Two Thousand Thirty Six [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 70.0
Subsequent Event [Member] | Four Point Eight Zero Percentage Of Bonds Maturing In September Two Thousand Thirty Six [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 70.0
Maximum [Member] | Term Loan Maturing 2022 [Member]
Debt Instrument [Line Items]
Debt instrument interest percentage	4.30%
Debt Instrument, Interest Rate, Effective Percentage				4.01%
Maximum [Member] | Term Loan Maturing 2022 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Debt instrument interest percentage	4.30%
Debt Instrument, Interest Rate, Effective Percentage				4.01%
Maximum [Member] | Pollution Control Series Maturing in August 2020 - 1.13% - 1.14% [Member]
Debt Instrument [Line Items]
Debt instrument interest percentage				1.42%
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	1.71%
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	1.71%			1.42%
Maximum [Member] | Bank term loan due in July 2020 - rates from: 2.44% - 2.45% [Member]
Debt Instrument [Line Items]
Debt instrument interest percentage	3.98%			3.02%
Minimum [Member] | Term Loan Maturing 2022 [Member]
Debt Instrument [Line Items]
Debt instrument interest percentage				4.00%
Debt Instrument, Interest Rate, Effective Percentage	4.01%
Minimum [Member] | Term Loan Maturing 2022 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Debt instrument interest percentage				4.00%
Debt Instrument, Interest Rate, Effective Percentage	4.01%
Minimum [Member] | Pollution Control Series Maturing in August 2020 - 1.13% - 1.14% [Member]
Debt Instrument [Line Items]
Debt instrument interest percentage				1.29%
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	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] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Debt Instrument [Line Items]
Debt instrument interest percentage	1.52%			1.29%
Minimum [Member] | Bank term loan due in July 2020 - rates from: 2.44% - 2.45% [Member]
Debt Instrument [Line Items]
Debt instrument interest percentage	3.02%			2.67%

XML

Income Taxes (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Entity Information [Line Items]
Effective income tax rates	94.30%	39.20%	31.20%	39.50%
Estimated annual effective income tax rate			30.90%	38.80%
THE DAYTON POWER AND LIGHT COMPANY [Member]
Entity Information [Line Items]
Effective income tax rates	38.80%	36.40%	31.30%	36.90%
Estimated annual effective income tax rate			30.40%	36.70%
Income Taxes Paid, Net			$ 26.2	$ 0.1

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Benefit Plans (Net Periodic Benefit Cost (Income)) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Pension [Member]
Contributions by employer			$ 5.0	$ 5.0
Service cost	$ 1.4	$ 1.4	2.8	2.8
Interest cost	3.5	3.7	7.1	7.4
Expected return on assets	(5.7)	(5.7)	(11.4)	(11.4)
Defined Benefit Plan, Curtailments	0.0	0.0	(4.1)	0.0
Prior service cost	0.2	0.5	0.6	1.0
Actuarial loss / (gain)	1.4	1.1	2.7	2.1
Net periodic benefit cost	0.8	1.0	5.9	1.9
Postretirement [Member]
Defined Benefit Plan, Funded Status of Plan	15.7		15.7		$ 15.8
THE DAYTON POWER AND LIGHT COMPANY [Member] | Pension [Member]
Contributions by employer			5.0	5.0
Service cost	1.4	1.4	2.8	2.8
Interest cost	3.5	3.7	7.1	7.4
Expected return on assets	(5.7)	(5.7)	(11.4)	(11.4)
Defined Benefit Plan, Curtailments	0.0	0.0	(5.6)	0.0
Prior service cost	0.3	0.7	0.8	1.5
Actuarial loss / (gain)	2.3	1.8	4.5	3.6
Net periodic benefit cost	1.8	$ 1.9	9.4	$ 3.9
THE DAYTON POWER AND LIGHT COMPANY [Member] | Postretirement [Member]
Defined Benefit Plan, Funded Status of Plan	$ 15.7		$ 15.7		$ 15.8

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Benefit Plans (Estimated Future Benefit Payments and Medicare Part D Reimbursements) (Details) - Pension [Member] $ in Millions	Jun. 30, 2017 USD ($)
2016	$ 12.5
2017	25.5
2018	26.0
2019	26.4
2020	26.7
2021 - 2025	139.6
THE DAYTON POWER AND LIGHT COMPANY [Member]
2016	12.5
2017	25.5
2018	26.0
2019	26.4
2020	26.7
2021 - 2025	$ 139.6

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Shareholder's Equity (Details) - USD ($)	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Class of Stock [Line Items]
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
Par value common shares (in USD per share)	$ 0.01		$ 0.01
Common stock, shares outstanding	41,172,173
PUCO merger equity ratio approval (at least)	50.00%
PUCO Equity Ratio	31.00%
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%
Adjustments to Additional Paid in Capital, Dividends in Excess of Retained Earnings	$ (9,000,000)	$ 0

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Contractual Obligations, Commercial Commitments and Contingencies (Narrative) (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Public Utility, Property, Plant and Equipment [Line Items]
Due to third parties, current	$ 1.4	$ 2.3
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	$ 33.1
Debt Obligation on 4.9% Equity Ownership [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Equity ownership interest	4.90%
Equity ownership interest aggregate cost	$ 71.8
Electric Generation Company [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Debt obligation	$ 1,465.4

XML

Business Segments (Narrative) (Details) - THE DAYTON POWER AND LIGHT COMPANY [Member]	6 Months Ended
	Jun. 30, 2017 mi² segment customer
Segment Reporting Information [Line Items]
Number of Operating Segments | segment	2
Approximate number of retail customers | customer	520,000
Service area, square miles | mi²	6,000

XML

Business Segments (Segment Financial Information) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Segment Reporting Information [Line Items]
External customer revenues	$ 298.1	$ 328.3	$ 622.0	$ 692.3
Intersegment revenues	0.0	0.0	0.0	0.0
Total revenues	298.1	328.3	622.0	692.3
Depreciation and amortization	26.5	36.0	54.5	69.4
Fuel Costs	54.0	60.2	108.1	127.1
Depreciation and amortization			54.5	69.4
Impairment of Long-Lived Assets Held-for-use	0.0	235.5	66.4	235.5
Interest expense	27.4	26.0	54.3	52.3
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	8.8	(225.1)	(74.4)	(222.3)
Net income / (loss) from continuing operations	0.5	(136.8)	(51.2)	(134.6)
Discontinued operations, net of tax	0.0	0.0	0.0	29.6
Net income/ (loss)	0.5	(136.8)	(51.2)	(105.0)
Capital expenditures	25.0	41.4	66.4	79.1
Total assets	2,210.4		2,210.4		$ 2,419.2
Operating Segments [Member] | Transmission and Distribution [Member]
Segment Reporting Information [Line Items]
External customer revenues	167.9	184.7	357.7	388.9
Intersegment revenues	0.3	0.4	0.6	0.7
Total revenues	168.2	185.1	358.3	389.6
Depreciation and amortization	18.6	17.6	36.7	34.8
Impairment of Long-Lived Assets Held-for-use		0.0	0.0	0.0
Interest expense	7.8	5.6	15.2	11.0
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	15.1	29.8	40.1	64.0
Capital expenditures	19.4	18.1	45.7	42.2
Total assets	1,647.5		1,647.5		1,710.5
Operating Segments [Member] | Generation [Member]
Segment Reporting Information [Line Items]
External customer revenues	127.4	141.4	259.2	299.6
Intersegment revenues	0.0	0.0	0.0	0.0
Total revenues	127.4	141.4	259.2	299.6
Depreciation and amortization	4.9	20.8	11.9	39.4
Impairment of Long-Lived Assets Held-for-use		857.1	66.3	857.1
Interest expense	0.2	0.1	0.2	0.2
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	13.2	(861.6)	(73.6)	(873.9)
Capital expenditures	5.1	23.3	19.2	36.3
Total assets	354.9		354.9		472.3
Other [Member]
Segment Reporting Information [Line Items]
External customer revenues	2.8	2.2	5.1	3.8
Intersegment revenues	1.3	0.9	2.7	2.2
Total revenues	4.1	3.1	7.8	6.0
Depreciation and amortization	3.0	(2.4)	5.9	(4.8)
Impairment of Long-Lived Assets Held-for-use		(621.6)	0.1	(621.6)
Interest expense	19.4	20.3	38.9	41.2
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	(19.5)	606.7	(40.9)	587.6
Capital expenditures	0.5	0.0	1.5	0.6
Total assets	622.5		622.5		673.6
Adjustments and Eliminations [Member]
Segment Reporting Information [Line Items]
External customer revenues	0.0	0.0	0.0	0.0
Intersegment revenues	(1.6)	(1.3)	(3.3)	(2.9)
Total revenues	(1.6)	(1.3)	(3.3)	(2.9)
Depreciation and amortization	0.0	0.0	0.0	0.0
Impairment of Long-Lived Assets Held-for-use		0.0	0.0	0.0
Interest expense	0.0	0.0	0.0	(0.1)
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	0.0	0.0	0.0	0.0
Capital expenditures	0.0	0.0	0.0	0.0
Total assets	(414.5)		(414.5)		(437.2)
Subsidiaries [Member]
Segment Reporting Information [Line Items]
External customer revenues	284.1	313.7	595.2	662.9
Intersegment revenues	0.0	0.0	0.0	0.0
Total revenues	284.1	313.7	595.2	662.9
Depreciation and amortization	22.0	36.8	45.5	71.1
Fuel Costs	49.9	55.6	100.0	118.5
Depreciation and amortization			45.5	71.1
Impairment of Long-Lived Assets Held-for-use	0.0	857.1	66.3	857.1
Interest expense	7.8	5.4	15.4	10.7
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	26.3	(835.3)	(37.4)	(789.2)
Net income/ (loss)	16.1	(531.6)	(25.7)	(497.9)
Capital expenditures	23.5	36.0	57.6	71.8
Total assets	1,848.6		1,848.6		2,035.1
Subsidiaries [Member] | Operating Segments [Member] | Transmission and Distribution [Member]
Segment Reporting Information [Line Items]
External customer revenues	168.2	185.1	358.3	389.6
Intersegment revenues	0.0	0.0	0.0	0.0
Total revenues	168.2	185.1	358.3	389.6
Depreciation and amortization	18.6	17.6	36.7	34.8
Impairment of Long-Lived Assets Held-for-use		0.0	0.0	0.0
Interest expense	7.8	5.3	15.2	10.5
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	15.1	30.1	40.1	64.5
Capital expenditures	19.4	18.1	45.7	42.2
Total assets	1,647.5		1,647.5		1,710.5
Subsidiaries [Member] | Operating Segments [Member] | Generation [Member]
Segment Reporting Information [Line Items]
External customer revenues	115.9	128.6	236.9	273.3
Intersegment revenues	0.0	0.0	0.0	0.0
Total revenues	115.9	128.6	236.9	273.3
Depreciation and amortization	3.4	19.2	8.8	36.3
Impairment of Long-Lived Assets Held-for-use		857.1	66.3	857.1
Interest expense	0.0	0.1	0.2	0.2
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	11.2	(865.4)	(77.5)	(853.7)
Capital expenditures	4.1	17.9	11.9	29.6
Total assets	201.1		201.1		324.6
Subsidiaries [Member] | Adjustments and Eliminations [Member]
Segment Reporting Information [Line Items]
External customer revenues	0.0	0.0	0.0	0.0
Intersegment revenues	0.0	0.0	0.0	0.0
Total revenues	0.0	0.0	0.0	0.0
Depreciation and amortization	0.0	0.0	0.0	0.0
Impairment of Long-Lived Assets Held-for-use		0.0	0.0	0.0
Interest expense	0.0	0.0	0.0	0.0
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	0.0	0.0	0.0	0.0
Capital expenditures	0.0	$ 0.0	0.0	$ 0.0
Total assets	$ 0.0		$ 0.0		$ 0.0

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Discontinued Operations (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating expenses				$ (0.7)
Loss from discontinued operations before income taxes	$ 0.0	$ 0.0	$ 0.0	(0.7)
Gain from disposal of discontinued operations	0.0	0.0	0.0	49.2
Income tax expense for discontinued operations	0.0	0.0	0.0	18.9
Net income from discontinued operations	$ 0.0	$ 0.0	$ 0.0	29.6
Cash flows from operating activities for discontinued operations				(0.7)
Cash flows from investing activities for discontinued operations				$ 75.5

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Held for Sale (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	$ 8.8	$ (225.1)	$ (74.4)	$ (222.3)
Miami Fort and Zimmer [Member]
Disposal Group, Including Discontinued Operation, Inventory	24.0		24.0
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	3.0	(9.7)	2.2	(16.2)
Disposal Group, Including Discontinued Operation, Property, Plant and Equipment	44.6		44.6
Disposal Group, Including Discontinued Operation, Assets	68.6		68.6
Disposal Group, Including Discontinued Operation, Accounts Payable	12.9		12.9
Disposal Group, Including Discontinued Operation, Accrued Income Tax Payable	4.9		4.9
Asset Retirement Obligation, Held for Sale	4.7		4.7
Disposal Group, Including Discontinued Operation, Other Liabilities	0.7		0.7
Disposal Group, Including Discontinued Operation, Liabilities	23.2		23.2
Subsidiaries [Member]
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	26.3	(835.3)	(37.4)	(789.2)
Subsidiaries [Member] | Miami Fort and Zimmer [Member]
Disposal Group, Including Discontinued Operation, Inventory	24.0		24.0
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	3.0	$ (9.7)	2.2	$ (16.2)
Disposal Group, Including Discontinued Operation, Property, Plant and Equipment	44.6		44.6
Disposal Group, Including Discontinued Operation, Assets	68.6		68.6
Disposal Group, Including Discontinued Operation, Accounts Payable	12.9		12.9
Disposal Group, Including Discontinued Operation, Accrued Income Tax Payable	4.9		4.9
Asset Retirement Obligation, Held for Sale	3.7		3.7
Disposal Group, Including Discontinued Operation, Other Liabilities	0.7		0.7
Disposal Group, Including Discontinued Operation, Liabilities	$ 22.2		$ 22.2

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Fixed-asset Impairment Fixed-asset Impairment (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Impairment of Long-Lived Assets Held-for-use	$ 0.0	$ 235.5	$ 66.4	$ 235.5
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	230.8
Impaired Assets to be Disposed of by Method Other than Sale, Amount of Impairment Loss			6.4
Peaking Generating Facilities [Member]
Impairment of Long-Lived Assets Held-for-use				4.7
THE DAYTON POWER AND LIGHT COMPANY [Member]
Impairment of Long-Lived Assets Held-for-use	0.0	857.1	66.3	857.1
THE DAYTON POWER AND LIGHT COMPANY [Member] | Stuart [Member]
Impairment of Long-Lived Assets Held-for-use			39.0	292.0
Impaired Assets to be Disposed of by Method Other than Sale, Amount of Impairment Loss			9.8
THE DAYTON POWER AND LIGHT COMPANY [Member] | Killen [Member]
Impairment of Long-Lived Assets Held-for-use			27.3	246.2
Impaired Assets to be Disposed of by Method Other than Sale, Amount of Impairment Loss			6.4
THE DAYTON POWER AND LIGHT COMPANY [Member] | Zimmer [Member]
Impairment of Long-Lived Assets Held-for-use				318.9
Level 3 [Member] | Stuart [Member]
Property, Plant, and Equipment, Fair Value Disclosure	3.3		3.3
Level 3 [Member] | Killen [Member]
Property, Plant, and Equipment, Fair Value Disclosure	7.9	84.3	7.9	84.3
Level 3 [Member] | Peaking Generating Facilities [Member]
Property, Plant, and Equipment, Fair Value Disclosure		5.2		5.2
Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Stuart [Member]
Property, Plant, and Equipment, Fair Value Disclosure	3.3	164.4	3.3	164.4
Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Killen [Member]
Property, Plant, and Equipment, Fair Value Disclosure	$ 7.9	84.3	$ 7.9	84.3
Level 3 [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member] | Zimmer [Member]
Property, Plant, and Equipment, Fair Value Disclosure		$ 111.0		$ 111.0